Temporary isolation systems for reservoirs

Abstract

An aqueous fluid is gelled in the production zone of a subsurface formation to form a temporary fluid-impermeable barrier. The fluid contains nanoparticles, polyacrylamide having a weight-average molecular weight of approximately 1.5 to 22 million daltons, and an encapsulated liquid crosslinker and / or crosslinking retarder. The barrier is formed by crosslinking the polyacrylamide. The nanoparticles remain dispersed in the crosslinked gel. The fluid-impermeable barrier remains effective for a period of at least one hour to two weeks while the downhole temperature in the well is at least 300°C.

Description

[Technical Field]

[0001] This application claims the benefit, as a continuation-in-part, of U.S. patent application Ser. No. 18 / 112,895, and U.S. patent application Ser. No. 63 / 616,173, filed Dec. 29, 2023, both of which are incorporated by reference in their entireties.

[0002] FIELD OF THE INVENTION The present disclosure relates to a fluid for temporarily isolating a target zone in an oil, gas, or geothermal well by forming a temporary seal or plug when the fluid gels in situ. The temporary seal or plug provides an impermeable barrier to fluid flow into the target zone. The barrier is stable to temperatures in excess of 300°C. The fluid is particularly useful in stimulation, drilling, completion, and cementing operations. [Background technology]

[0003] Water-based well treatment fluids are commonly used in drilling, stimulation, completion, and cementing operations of subterranean formations. Treatment designs typically require such fluids to exhibit a certain level of viscosity. Therefore, viscosifying polymers are often used in such fluids to provide the necessary viscosity. A problem that arises in the field is the loss of fluid into high permeability zones of the formation or into the wellbore. Loss of circulating fluid into the formation or into the wellbore can dramatically increase the cost of such operations.

[0004] During drilling and completion operations, fluids can be lost in high-permeability zones or natural fractures in the formation. Such increased costs can result from fluid loss and overheating, drill bit damage, reduced drilling rates, and blowouts due to reduced fluid levels in the well. During cementation, insufficient cement packing can result in zonal isolation failure. In some cases, loss of circulating fluid can cause formation collapse in the wellbore and deep blockage of the formation. This, in turn, can cause widespread damage, requiring the reservoir to be abandoned. To stop or slow the loss of circulating fluid, it is desirable to quickly block the flow path causing such loss. Lost circulation materials (LCMs) are often added to the fluid, which can bridge or block seepage into the formation. Unfortunately, the flow characteristics of most LCMs do not achieve effective blockage, especially in wells with high temperatures and / or pressures.

[0005] In well stimulation operations, such as hydraulic fracturing, acid stimulation, steam injection, and thermal injection, the recovery efficiency of hydrocarbon fluids within a formation can be limited by flow mechanisms associated with low-permeability zones within the formation. Typically, fluids produced during such operations can be recovered from multiple producing zones within a reservoir. Such zones typically exhibit varying levels of permeability. At times, it is desirable to seal high-permeability zones in order to produce fluids from blocked or low-permeability zones within a reservoir. Additionally, it may be desirable to temporarily isolate a target zone in order to produce fluids from the target zone. Such selective stimulation methods become more important as well lifespans and well productivity decrease.

[0006] Traditionally, selective stimulation of a target zone within a formation required the use of a perforating gun, which was transported into a well on wireline or tubing and positioned adjacent to the target zone. The gun was then fired to perforate the target zone. Fracturing fluid was pumped into the target zone under pressure exceeding that at which the target zone fractured. A mechanical device, such as a straddle packer, or plug, or sand packing, was installed in the well between the just-fractured zone and a non-stimulated zone to isolate the stimulated zone. The gun was then repositioned by wireline to another zone or formation, and then selectively perforated the desired zone or formation. This procedure was repeated until all desired zones had been perforated. After completion operations were completed, each plug had to be drilled and removed from the well to allow fluid to be produced through the well to the surface. This process was time-consuming and expensive.

[0007] More recently, selective isolation of targeted production intervals within a well has been achieved through the use of polymer gels that can temporarily seal the zone of interest from other zones. For example, U.S. Patent No. 8,636,066 discloses the use of borated galactomannan gum as a temporary sealant.

[0008] Additionally, split-flow chemical systems have been developed that provide a temporary barrier to the ingress of process fluids into higher permeability zones. Such systems allow production from low-permeability zones by diverting flow from the blocked high-permeability zone to the low-permeability zone. See, for example, U.S. Patent Nos. 9,919,966, 9,920,610, 10,041,327, and 10,988,678.

[0009] Gelling agent systems for use in zone isolation and as diversion agents often exhibit several drawbacks. For example, temporary plugs are only effective for relatively short periods of time. Furthermore, such systems are ineffective at sealing production zones at high bottomhole temperatures. This is particularly true in the case of thermal energy extraction or recovery from thermally productive formations. In such processes, aqueous systems are pumped deep into characteristically high-temperature geothermal wells, where usable energy is extracted and removed. The recovered thermal energy can be used to drive turbines and to generate power through conversion to heat or electricity. One of the key aspects of geothermal energy production is managing heat losses within the well, while heat is extracted using pumped aqueous fluids used as a capture and transport medium. Heat recovery from geothermal wells can be maximized by targeting more productive zones by sealing less productive zones. However, temporary seals for this purpose must be able to withstand the high temperatures encountered in geothermal wells.

[0010] Therefore, there is a need for alternative fluids and systems that function as flow splitters and LCMs.

[0011] It should be understood that the foregoing description has been provided for illustrative purposes only and is not intended to limit the scope or subject matter of the appended claims or any related patent application or patent. Summary of the Invention

[0012] An aqueous fluid is provided that can seal selected permeable zones within a formation penetrated by a well. The aqueous fluid contains polyacrylamide having a weight average molecular weight of approximately 1.5 million to 22 million daltons, nanoparticles, and an encapsulated liquid crosslinker. The aqueous fluid may be used in stimulation operations. In one embodiment, the fluid may be used to isolate a target zone within a formation to produce hydrocarbons from the target zone. In another embodiment, the fluid may be used to isolate a high permeability zone in order to divert subsequent pumped fluid to a lower permeability zone. The fluid may be used in the treatment of geothermal wells as well as oil or gas wells.

[0013] In one embodiment, a method for improving productivity in a production well is provided, in which a high-permeability target zone within the well is plugged and then the flow of pumped treatment fluid is diverted from the plugged target zone to a low-permeability zone. The aqueous fluid initially pumped into the well contains (i) nanoparticles, (ii) polyacrylamide having a weight-average molecular weight of approximately 1.5 million to 22 million daltons, and (iii) an encapsulated liquid crosslinker. Upon release, the crosslinker interacts with the nanoparticles and polyacrylamide to form a viscous gel. The downhole temperature within the well at the time of crosslinker release is at least 85°C. The viscous gel flows to the target zone within the formation, forming a barrier plug across the target zone. The barrier plug is stable and typically begins to degrade only after an extended period of time. While degradation may begin as soon as one hour after fluid pumping, degradation typically does not begin until at least eight hours after fluid pumping. In other cases, degradation may be delayed for up to 48 hours after fluid pumping. In yet other cases, decomposition may not occur until two weeks after pumping of the fluid. The subsequently introduced fluid stream is diverted from the plugged target zone to a second zone. Downhole temperatures within the well during such diverted subsequently introduced fluid stream may be at least 125°C, in some cases at least 300°C, and in other cases as high as 350°C.

[0014] In another embodiment, a method for stimulating a subterranean formation is provided, wherein a first aqueous fluid is pumped into a reservoir penetrating the formation. The first aqueous fluid contains nanoparticles, polyacrylamide having a weight-average molecular weight of about 1.5 million to 22 million daltons, and an encapsulated liquid crosslinker. The first aqueous fluid is gelled, thereby forming a plug in a target zone within the formation. The plug forms an effective fluid-impermeable barrier for a period of at least 48 hours at downhole temperatures of 300°C or greater. One or more second fluids may then be pumped into the reservoir. The flow of the one or more second fluids is diverted from the target zone to one or more second zones. The permeability of the target zone is higher than the permeability of the one or more second zones.

[0015] In another embodiment, a method for increasing productivity in a well having multiple production zones is provided, wherein an aqueous fluid is introduced into the target zone after drilling and fracturing the target zone. The aqueous treatment fluid contains (i) nanoparticles, (ii) polyacrylamide having a weight-average molecular weight of about 1.5 million to 22 million daltons, and (iii) an encapsulated liquid crosslinker. The target zone is isolated from a non-stimulated zone of the well by gelling the fluid to form a temporary plug. In one embodiment, the downhole temperature in the well is 300°C or greater.

[0016] In another embodiment, a method for improving productivity in a well having multiple production zones is provided, wherein an aqueous fluid is introduced into a predetermined production zone, the aqueous treatment fluid containing (i) nanoparticles, (ii) polyacrylamide having a weight-average molecular weight of about 1.5 million to 22 million daltons, and (iii) an encapsulated liquid crosslinker. The predetermined production zone is isolated from other zones of the well by gelling the fluid. The downhole temperature in the well is 300°C or greater. The predetermined production zone is treated with a stimulation fluid. Stimulation of the isolated predetermined production zone may be for a period of at least 48 hours.

[0017] In yet another embodiment, a method for treating a subterranean formation penetrated by a well and increasing fluid productivity from the formation is provided. In this method, a first aqueous fluid is introduced into the well. The first aqueous fluid contains (i) nanoparticles, (ii) polyacrylamide having a weight-average molecular weight of about 1.5 million to 22 million daltons, and (iii) a liquid crosslinker. Either the liquid crosslinker is encapsulated, or the aqueous fluid further contains a crosslinking retarder selected from the group consisting of metal lactate or ammonium lactate, hydroxylated glycine, and alkoxylated sugar alcohol. In one embodiment, the entire liquid crosslinker is encapsulated, and the aqueous liquid further contains at least one of the aforementioned crosslinking retarders. The aqueous fluid is then gelled, forming a plug in a target zone within the formation. The plug constitutes a fluid-impermeable barrier at downhole temperatures of 85°C or greater for a period of one hour to two weeks. [Brief explanation of the drawings]

[0018] The following drawings are part of the present specification and are included to demonstrate certain aspects of various embodiments of the present disclosure and are referenced in this detailed description. [Figure 1] FIG. 1 is a dynamic light scattering (DLS) diagram of an encapsulated cross-linker used in an aqueous fluid disclosed herein, showing the normalized distribution of the cross-linker when encapsulated by a lecithin-containing layer. [Figure 2] 1 is a viscosity profile over time at ambient temperature of an aqueous fluid containing 30,000 ppm partially hydrolyzed poly(acrylamide) (HPAM), 750 ppm alumina nanoparticles, and a lecithin-encapsulated crosslinker. [Figure 3] Viscosity profile at 100 s / s at 25° C. of an aqueous fluid containing 30,000 ppm partially hydrolyzed poly(acrylamide) (HPAM), 750 ppm alumina nanoparticles, and lecithin-encapsulated crosslinker. [Figure 4]Viscosity profile at 100 s / s at 40° C. of an aqueous fluid containing 30,000 ppm partially hydrolyzed poly(acrylamide) (HPAM), 750 ppm alumina nanoparticles, and lecithin-encapsulated crosslinker. [Figure 5] Viscosity profile at 90° C. and 100 s / s of an aqueous fluid containing 30,000 ppm partially hydrolyzed poly(acrylamide) (HPAM), 750 ppm alumina nanoparticles, and lecithin-encapsulated crosslinker. [Figure 6] 100 / sec viscosity profiles at 25° C. of aqueous fluids containing 250 ppm alumina nanoparticles, encapsulated crosslinker, and various amounts of HPAM. [Figure 7] 100 / sec viscosity profiles at 90° C. of aqueous fluids containing 250 ppm alumina nanoparticles, encapsulated crosslinker, and various amounts of HPAM. [Figure 8] 1 is a viscosity profile at 90° C. of encapsulated versus unencapsulated crosslinker in an aqueous fluid containing 15,000 ppm HPAM and 250 ppm alumina oxide nanoparticles. [Figure 9] FIG. 1 is a schematic diagram illustrating a test system having physical properties that simulate a geothermal well. [Figure 10] 1 shows the aqueous fluids disclosed herein forming a temporary fluid barrier at 300° C. and a pressure differential of 2,000 psi. [Figure 11] 1 shows the viscosity retardation of polyacrylamide gelling fluids containing alkoxylated sorbitol with ethylene glycol as a retarding crosslinker. [Figure 12] 1 shows the viscosity retardation of polyacrylamide gelling fluids containing 50% glycine, N-(hydroxymethyl), monosodium salt as a retarding crosslinker. [Figure 13] 1 shows the viscosity retardation of polyacrylamide gelling fluids containing metal lactate as a retarding crosslinker. [Figure 14] 1 is a viscosity profile of a polyacrylamide gelling fluid containing a metal lactate as a retarding crosslinker. [Figure 15]1 shows the dynamic properties of polyacrylamide gelling fluids containing metal lactate as a retarding crosslinker subjected to high temperature and pressure. [Figure 16] 1 illustrates the stability of polyacrylamide gelling fluids when exposed to extreme thermal conditions. DETAILED DESCRIPTION OF THE INVENTION

[0019] The features and advantages of the present disclosure, as well as additional features and benefits, will be readily apparent to those skilled in the art upon consideration of the following detailed description of exemplary embodiments thereof and upon reference to the accompanying drawings. It is to be understood that the description herein and the accompanying drawings of exemplary embodiments are not intended to limit the scope of the claims of this patent or any patent or patent application claiming priority to this patent. On the contrary, the present invention is intended to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the claims. Many changes may be made to the specific embodiments and details disclosed herein without departing from such spirit and scope.

[0020] As used herein and throughout the various sections, the terms "disclosure," "this disclosure," and variations thereof are not intended to refer to every possible embodiment encompassed by the disclosure or any particular claim. Accordingly, the subject matter of each such reference should not be considered necessary for or a part of every embodiment of the specification or every embodiment of any particular claim solely by virtue of such reference.

[0021] Certain terms are used herein and in the appended claims to refer to particular components. As one skilled in the art will understand, different people may refer to components by different names. This specification does not intend to distinguish between components that differ in name but not function. Additionally, the terms "including" and "comprising" are used herein and in the appended claims in an open-ended manner and should therefore be interpreted to mean "including, but not limited to." Furthermore, references to elements and aspects in the singular in this specification and in the appended claims do not necessarily limit the disclosure or appended claims to only one such element or aspect, but should generally be interpreted to mean one or more, as may be appropriate and desirable in each particular instance.

[0022] All ranges disclosed herein are inclusive of their endpoints. Numerical ranges with lower and upper endpoints are intended to further encompass any number and any range that falls within those endpoints. For example, all ranges of values ​​(such as "a to b," or "about a to about b," or "about a to b," "approximately a to b," "between about a and about b," and any similar expression, where "a" and "b" represent numerical values ​​of degree or measurement) are to be understood to describe all numbers and ranges encompassed within the broader range of values ​​and inclusive of the endpoints.

[0023] "Optional" or "optionally" means that the subsequently described event or circumstance may or may not occur, and that the description includes instances where the event occurs and instances where the event does not occur.

[0024] The aqueous fluid used in the disclosed method contains three major components: (i) nanoparticles, (ii) polyacrylamide having a weight average molecular weight of about 1.5 million to 22 million daltons, and (iii) a liquid crosslinker. In one embodiment, the liquid crosslinker is encapsulated in a layer that delays the release of the crosslinker in situ. In another embodiment, the fluid may contain a crosslinking retarder. In another embodiment, the fluid contains both an encapsulated crosslinker and a delayed crosslinker.

[0025] The aqueous fluid generally does not exhibit premature gelation when pumped downhole at temperatures of about 100°C to about 120°C. Typically, the initial viscosity of the fluid remains ungelled for at least one hour at temperatures below 125°C. This is a significant advantage over prior art fluids, which tend to undergo gelation within minutes at temperatures above 90°C due to shunting. The presence of an encapsulated liquid crosslinker and / or crosslink retarder in the aqueous fluid allows the fluid to be efficiently pumped into the well in a liquid state, even at elevated temperatures, until the fluid reaches its intended target.

[0026] Aqueous fluids are typically used in high-temperature reservoirs. In one embodiment, aqueous fluids are used to target selected zones within wells by remaining in a stable gel state for 24 to 48 hours at temperatures above 200°C to 250°C, sometimes above 300°C, and in other cases as high as 350°C and even 500°C. In most cases, complete degradation of the gel may not occur until about one week after degradation begins. In one embodiment, the gel can withstand differential pressures of 800 psi (typically above 1,000 psi, often above 15,000 psi) at such downhole temperatures. At such temperatures and pressures, the gel is stable for one hour, often eight hours, typically up to 48 hours, and in some cases up to two weeks.

[0027] After being pumped into the reservoir, the fluid forms a stable, fluid-impermeable gelling barrier or plug, i.e., a barrier or plug that isolates, substantially impairs, or prevents fluid flow to locations where fluid flow is undesirable, such as previously stimulated intervals.

[0028] In a preferred embodiment, the well into which the fluid is introduced is a geothermal well. During geothermal well stimulation, temporary blocking of the high permeability zone is essential to selectively direct the injected acid into the target formation.

[0029] In other embodiments, the fluid may be introduced into a gas or oil well. The well may be a completed open-hole well with a slotted or pre-drilled liner.

[0030] The thermal stability of the gelled fluid can be attributed to the presence of the polyacrylamide in combination with the nanoparticles. For example, the thermal stability of the polymer can be increased by the presence of nanoparticles.

[0031] The polyacrylamide, when added to the nanoparticles and crosslinker, can be in the form of an emulsion, oil slurry, or dry powder.

[0032] In one embodiment, the aqueous fluid before being gelled may contain from about 2,000 to about 50,000 ppm by weight of polymer, more typically from about 10,000 to 30,000 ppm by weight, and more desirably from about 12,000 to about 20,000 ppm by weight.

[0033] In one embodiment, the polyacrylamide incorporated into the crosslinker and nanoparticles may be partially hydrated in an aqueous emulsion or formulated into a slurry in which droplets of an aqueous phase containing the polyacrylamide are dispersed in an oil phase. Suitable oils include mineral oil and diesel oil.

[0034] In one embodiment, powdered polyacrylamide can be mixed with the aqueous hydration medium prior to and / or during pumping into the well. In such cases, the polyacrylamide powder is at least 80% by weight active, preferably at least 90% by weight, and in some cases 95% by weight active.

[0035] In one embodiment, the hydrating media may be pumped down the wellbore through a main line, and dry polyacrylamide powder may be injected into the hydrating media during pumping, where it is mixed with the crosslinker and nanoparticles. In one embodiment, the polyacrylamide may be in the form of microbeads. The microbeads are often between about 0.5 and 2.0 microns in diameter.

[0036] Typically, the polyacrylamide is substantially uniformly distributed throughout the aqueous fluid before the fluid is gelled.

[0037] The fluid, when pumped into the well (or when formulated in the well from dry polyacrylamide), has a viscosity in the range of less than 50 cP or even less than 15 cP. (Viscosity measurements referred to herein are measured on a Malvern Kinexus Pro rotational rheometer at 100 s. -1 , performed at 25°C).

[0038] When an aqueous fluid contains an encapsulated liquid crosslinker, a gel forms upon degradation of the encapsulation medium surrounding the liquid crosslinker. At that point, a reaction between the polyacrylamide and the crosslinker occurs. Degradation of the encapsulation medium can occur by hydrolysis, solvolysis, melting, or other mechanisms. Because the crosslinker is encapsulated, the timing of gelation of the fluid can be controlled by varying the parameters that result in the degradation of the encapsulation medium.

[0039] The timing of gelation can also be controlled by the use of a crosslinking retarder in the aqueous fluid, where the crosslinking retarder is selected from metal or ammonium DL-lactic acid, hydroxylated glycine, and alkoxylated sugar alcohol. Such crosslinking retarders can be used in combination with the encapsulated liquid crosslinkers described herein. The encapsulated liquid crosslinker and / or delayed crosslinker can extend the crosslinking delay or gelation time by 1 hour to at least 2 hours when exposed to temperatures of 100°C to 120°C or higher. In other words, the initial viscosity of the pumpable fluid is maintained for at least 2 hours at temperatures of 100°C to 120°C or higher.

[0040] Disruption of the gelling fluid does not require the introduction of a disrupting agent into the well or the inclusion of a disrupting agent in the aqueous fluid. Once the gel is disrupted, it does not self-heal; i.e., no bonding interaction occurs between the polyacrylamide and the crosslinker upon disruption. Therefore, disrupted gels can be more easily removed from the well during backflow. In some cases, the gel does not return to its watery consistency for more than seven days after the fluid was first pumped into the reservoir.

[0041] The ionic charge of the polyacrylamide may be between 0 and 100 percent. The polyacrylamide is preferably ionic, for example anionic.

[0042] The polyacrylamide is typically a homopolymer of acrylamide (PAM), a poly(acrylamide) alkali metal salt, or a partially hydrolyzed poly(acrylamide) (HPAM).

[0043] The weight-average molecular weight of polyacrylamide is about 8 million to about 22 million daltons, typically about 5 million to about 20 million daltons, and sometimes between about 6 million and 8 million daltons. The molecular weight of the polymer can depend on the level of hydrolysis. In some cases, the degree of hydrolysis of the acrylamide units of the polymer is about 0.15 to about 0.40, more typically about 0.25 to about 0.35, and most typically about 0.30.

[0044] In one embodiment, the preferred polyacrylamide is

[0045] [ka] HPAM is a linear polymer of acrylamide monomer, which can be represented by the structural formula: wherein the molar ratio of m:n is from about 5:95 to about 95:5. Typically, the polymer is a flexible chain structure characterized by a random coil.

[0046] The gel is formed in situ by cross-linking polyacrylamide with a liquid cross-linking agent. The cross-linking agent may be encapsulated. Cross-linking does not occur until the cross-linking agent is released. Typically, the encapsulating medium does not decompose and release the cross-linking agent until downhole temperatures of 85 to about 135°C, more typically about 90 to about 120°C, are reached.

[0047] The crosslinker may be suitable for forming ionic and / or covalent bonds with polyacrylamide. More typically, the crosslinker is a metal or forms a coordination or metal complex with the polymer chain. Preferably, the metal is a source of a polyvalent metal ion suitable for crosslinking with functional groups on the polymer, such as the acrylamide or carboxylate groups on PAM and / or HPAM. The crosslinker may be, for example, an organometallic, and the metal may be Cr(III), Cr(IV), Ti(IV), Al(III), Zr(IV), Ca2+, Mg2+, Zn2+, and combinations thereof. The metal is preferably a chromium compound, most preferably Cr(III) ion. The counterion or ligand of the crosslinker may include acetate, propionate, lactate, oxalate, malonate, maleate, succinate, glutamate, or citrate. Alternatively, the crosslinker may be a complex of one of the aforementioned metals with an inorganic counterion, such as a phosphonate, sulfonate, carbonate, or halide. In a preferred embodiment, the cross-linking agent is chromium acetate or chromium chloride.

[0048] In a preferred embodiment, the gel formed is a hydrolyzed polyacrylamide / chromium acetate gel. 3+ The combination of results in a physically crosslinked gel due to the complexes formed between the metal and the carboxylic acid groups on the HPAM or PAM.

[0049] Methods for encapsulating crosslinkers are well known in the art. For example, the crosslinker may be encapsulated by a polymer. Polymers suitable for degradation at temperatures above 85°C include homo- and copolymers of glycolate and lactic acid, polycarbonates, polyanhydrides, polyorthoesters, and polyphosphazenes. Exemplary polymers include, for example, poly(lactic-co-glycolic acid).

[0050] In a preferred embodiment, the encapsulating layer is an organic phosphorus, such as a phospholipid, such as lecithin. The lecithin can be natural or synthetic. Suitable lecithins include, in particular, soybean lecithin or soybean lecithin. Preferred phospholipids and lecithins include one or more glycerophospholipids (e.g., phosphatidylcholine, phosphatidylethanolamine, phosphatidylinositol, phosphatidylserine, and phosphatidic acid).

[0051] The crosslinking agent can be encapsulated by the polymer using known methods, such as double emulsion and spray drying. The double emulsion method typically involves emulsifying an aqueous solution containing the crosslinking agent in a first organic compound containing the encapsulating polymer layer. A primary emulsion is generated by mixing. The organic compound may be, for example, dichloromethane, ethyl acetate, cyclohexane, or a mixture thereof. The primary emulsion is then dispersed in a second aqueous solution and emulsified to generate a secondary emulsion. The second aqueous solution may contain a hydrophilic stabilizer, such as polyvinyl alcohol and a surfactant. The secondary emulsion is then evaporated by freeze drying, spray drying, or another method to remove the first organic compound and the second aqueous solution, leaving behind the encapsulated crosslinking agent. Spray drying generally involves atomizing a liquid feedstock containing the encapsulating polymer layer and the crosslinking agent into a spray of droplets. The droplets are typically dried with hot air in a drying chamber. The spray is typically generated by a rotary or nozzle atomizer.

[0052] The total amount of crosslinker in the aqueous fluid (either as encapsulated or unencapsulated crosslinker) varies over a wide range of from about 1 mg to about 20,000 mg per liter of aqueous fluid, preferably in the range of from about 1 mg / L to about 10,000 mg / L, and most preferably in the range of from 1 mg / L to 5,000 mg / L.

[0053] In one embodiment, the retarding crosslinker is a metal lactate or ammonium lactate, a salt of hydroxylated glycine or an alkoxylated sugar alcohol, or a combination thereof.

[0054] Suitable metal lactates are lactic acids containing alkali metals or alkaline earth metals, with preferred alkali metals being sodium and potassium and preferred alkaline earth metal being calcium.

[0055] When the crosslinking retarder is a salt of hydroxylated glycine, the salt may be an alkali metal salt such as sodium and potassium, an alkaline earth metal salt such as calcium, magnesium, a transition metal salt such as copper, zinc, zirconium, titanium, and ammonium. The hydroxylated glycine used as the crosslinking retarder is preferably a salt of N-hydroxymethylglycine or N,N-bis(2-hydroxyethyl)glycine, for example, the monosodium salt.

[0056] In another embodiment, the delayed cross-linking agent may be an alkoxylated sugar alcohol, which may be or be derived from sucrose, glucose, or sorbose, such as sorbitol, containing six hydroxyl groups derivatized with ethylene oxide, propylene oxide, or butene oxide. A preferred alkoxylated sugar alcohol is alkoxylated sorbitol, such as ethoxylated sorbitol. In one embodiment, the alkoxylated sorbitol has the following molecular formula: (C2H4O) n (C2H4O) n (C2H4O) n (C2H4O) n (C2H4O) n (C2H4O) n C6H 14 O6 (wherein each n can be 1-4).

[0057] In one embodiment, the alkoxylated sugar alcohol may be combined with ethylene glycol in a molar ratio of about 1 to about 5.

[0058] The nanoparticles have a number-average particle size suitable for forming a gelling fluid before being introduced into an aqueous fluid. For example, the nanoparticles may be less than 2,000 nm in diameter, typically less than 1,000 nm, preferably up to about 500 nm in diameter, more preferably about 5 to about 250 nm in diameter, and often about 5 to about 100 nm, 5 to about 50 nm, or about 9 to about 25 nm in diameter. [Generally, as used herein, "particle size" refers to the number-average particle size along the longest particle dimension and can be determined using particle size measurement methods known in the art, such as laser light scattering (static or dynamic light scattering), or direct determination methods, such as scanning electron microscopy (SEM) or transmission electron microscopy (TEM)]. Typically, the nanoparticles referred to herein are spherical.

[0059] The concentration of nanoparticles in the aqueous fluid containing the crosslinker and polyacrylamide prior to gelation can be 0.1 wt. % (8.34 pounds per 1000 gallons ("pptg")) or greater, based on the total weight of the aqueous fluid. In other cases, the concentration of nanoparticles in the aqueous fluid can be greater than 0.5 wt. % (about 41.7 pptg) based on the total weight of the aqueous fluid. In one embodiment, the concentration of nanoparticles in the aqueous fluid can range from about 2 wt. % to about 20 wt. % (about 167 pptg to about 1670 pptg). Once the polyacrylamide is crosslinked, the nanoparticles remain dispersed in the crosslinked gel.

[0060] Suitable nanoparticles include inorganic nanoparticles, such as metal or metalloid oxides or hydroxides, such as silica, alumina, titania, silicic acid, aluminum oxide, aluminum hydroxide, aluminum hydroxide, aluminosilicate, zirconium oxide, zirconium hydroxide, zirconium hydroxide, tungsten oxide, or iron oxide, as well as metal or metalloid carbides, such as tungsten carbide, silicon carbide, and boron carbide, and metal or metalloid nitrides, such as titanium nitride, boron nitride, and silicon nitride, or combinations thereof. Metal nanoparticles include alkali metals, alkaline earth metals, inner transition metals (lanthanides or actinides), transition metals, or post-transition metals. Examples of such metals include magnesium, aluminum, iron, tin, titanium, platinum, palladium, cobalt, nickel, vanadium, chromium, manganese, zirconium, ruthenium, hafnium, tantalum, tungsten, rhenium, osmium, alloys thereof, and barium or strontium titanate, or combinations thereof. Preferred nanoparticles include alumina, boehmite, and zirconia.

[0061] Other suitable nanoparticles include fullerenes, nanotubes, graphene, such as nanographite, nanodots, nanorods, nanodiamonds, polysilsesquioxanes, antimony oxide, vanadium oxide, and magnesium oxide, and mixtures thereof.

[0062] Fullerenes include cage-like hollow polyhedral allotropic carbon forms having a polyhedral structure, including those having from about 20 to about 100 carbon atoms.

[0063] Nanographite can be described as a cluster of graphite plate-like sheets with a stacking structure of one or more layers of graphite plate-like two-dimensional structures of fused hexagonal rings.

[0064] Suitable graphenes include nanographenes and graphene fibers (graphene particles having an average largest dimension greater than 1 μm, a second dimension less than 1 μm, and an aspect ratio greater than 10, where the graphene particles form interconnected chains). Graphene and nanographene fibers are essentially two-dimensional particles having one or more layers of fused hexagonal rings. Typically, graphene nanoparticles can be prepared by exfoliation of graphite sources such as nanographite, graphene, or nanographene, graphite, and intercalated graphite. Exemplary exfoliation methods include fluorination, acid intercalation, and high-temperature treatment after acid intercalation. Exfoliation of nanographite provides nanographene with fewer layers than non-exfoliated nanographite. Exfoliation of nanographite can provide nanographene as a single sheet one molecule thick or as a layered stack of sheets. In one embodiment, the exfoliated nanographene may have fewer than 50 single-sheet layers, and in another embodiment, fewer than 5 single-sheet layers.

[0065] Suitable nanotubes include carbon nanotubes, inorganic nanotubes (e.g., boron nitride nanotubes), metallized nanotubes, or combinations thereof. Suitable nanotubes include single-walled nanotubes (SWNTs) or multi-walled nanotubes (MWNTs).

[0066] Suitable polysilsesquioxanes (also called polyorganosilsesquioxanes or polyhedral oligomeric silsesquioxane (POSS) derivatives) have the general formula RSiO, with defined closed or open cage structures (closo or nido structures). 1.5 Polysilsesquioxanes containing the POSS structure can be prepared by acid- and / or base-catalyzed condensation of functionalized silicon-containing monomers such as tetraalkoxysilanes, including tetramethoxysilane and tetraethoxysilane, and alkyltrialkoxysilanes, such as methyltrimethoxysilane and methyltrimethoxysilane.

[0067] Additionally, the nanoparticles may be nanolayered silicates or nanoclays (hydrated or anhydrous silicates, plate-like minerals with a layered structure). Examples of nanoclays include aluminosilicate clays such as kaolin (including vermiculite), halloysite, bentonite, smectite (including montmorillonite), saponite, beidellite, nonthrite, hectorite, allophane, and illite, as well as titanium sulfate and zirconium sulfate. Nanoclays may or may not be exfoliated into individual sheets. Other nano-sized mineral fillers of similar structure that can be used include talc, mica (including muscovite, phlogopite, or phengite). Nanoclay platelets typically range in thickness from about 3 to about 1000 angstroms, in planar dimensions ranging from about 0.01 μm to 100 μm, and from about 90 to about 800 μm. 2 / g. The aspect ratio (length to thickness) is generally about 10 to about 10,000.

[0068] Additionally, the nanoparticles can be derivatized to include a variety of different functional groups, such as, for example, carboxy (e.g., carboxylic acid and anhydride groups such as maleic anhydride), epoxy, ether, ketone, amine, hydroxy, alkoxy, alkyl, aryl, aralkyl, alkaryl, lactone, and functionalized polymeric or oligomeric groups, etc. In one embodiment, the nanoparticles include a combination of derivatized and underivatized nanoparticles.

[0069] The nanoparticles may be further derivatized to include one or more functional groups that are hydrophilic, hydrophobic, oxophilic, lipophilic, or lipophilic. In one embodiment, such functional groups may include (i) organosilicon materials, (ii) fluorinated organic acids or reactive derivatives, (iii) linear or branched alkyl organic acids or reactive derivatives, (iv) substituted alkyl organic acids or reactive derivatives, (v) aryl or substituted aryl organic acids or reactive derivatives, and (vi) mixtures thereof.

[0070] In one embodiment, the surface modifier is an organic acid with a long chain alkyl, aryl, or fluoro group. Suitable organic acids include carboxylic acids, sulfonic acids, phosphoric acids, phosphonic acids, and phosphinic acids.

[0071] Exemplary carboxylic acids include those of the formula R-COOH, where R is a straight or branched chain C-C 24 , preferably C 12 ~C 21 Hydrocarbon groups or their hydroxylated derivatives, or C6-C 20 The organic acid may be an aryl, alkylaryl, or arylalkyl group. Suitable carboxylic acids include behenic acid, palmitic acid, and the like. In one embodiment, the organic acid of the hydrophobic and / or oleophobic surface modifier has two or more carboxylic acid moieties, and preferably the number average molecular weight of the organic acid is from about 80 g / mol to about 2,000 g / mol.

[0072] Suitable reactive derivatives of the organic acids referred to herein include acid chlorides such as those of formula R'(C=O)Cl, esters such as those of formula R'-COOR" and the corresponding acid anhydrides. In one embodiment, R' and R" may be a C1-C8 hydrocarbon group or R as defined above.

[0073] In one embodiment, the hydrophobic and / or oleophobic surface modifier may be an organophosphoric acid, organophosphonic acid, or organophosphinic acid, or a derivative thereof. The organic group of the anchor may be monomeric or polymeric.

[0074] Examples of monomeric phosphates and derivatives include those having the structure (RO) x -P(O)-(OR') ywhere x is 1-2, y is 1-2, and x+y=3; R is preferably a radical having a total of 1-30, preferably 2-20, more preferably 6-18 carbons; and R' is H, an alkali metal, e.g., a metal such as sodium or potassium, or a lower alkyl having 1-4 carbons, such as methyl or ethyl. Preferably, a portion of R' is H. The organic component (R) of the phosphoric acid may be a saturated or unsaturated aliphatic group, or an aryl or aryl-substituted moiety. At least one of the organic groups may contain a terminal or omega functionality, as described below.

[0075] Examples of monomeric phosphonic acids or derivatives include compounds or mixtures of compounds having the following formula:

[0076] [ka] wherein a is 0-1, b is 1, c is 1-2, and a+b+c is 3; R and R" are preferably each independently a radical having a total of 1-30, preferably 2-20, more preferably 6-18 carbons; and R' is H, a metal, such as an alkali metal, e.g., sodium or potassium, or a lower alkyl having 1-4 carbons, e.g., methyl or ethyl. Preferably, at least some of the R's are H. The organic components of the phosphonic acid (R and R") can be saturated or unsaturated aliphatic groups or aryl or aryl-substituted moieties. At least one of the organic groups can contain a terminal or omega functionality, as described below.

[0077] Examples of monomeric phosphinic acids or derivatives are compounds or mixtures of compounds having the following formula:

[0078] [ka] wherein d is 0-2, e is 0-2, f is 1, and d+e+f is 3; R and R" are preferably each independently a radical having a total of 1-30, preferably 2-20, carbon atoms, more preferably 6-18 carbon atoms; and R' is H, a metal such as an alkali metal, e.g., sodium or potassium, or a lower alkyl having 1-4 carbon atoms, e.g., methyl or ethyl. Preferably, a portion of R' is H. The organic components (R, R") of the phosphinic acid can be saturated or unsaturated aliphatic groups, or aryl or aryl-substituted moieties. Examples of organic groups that can comprise R and R" include long- and short-chain aliphatic hydrocarbons, aromatic hydrocarbons, substituted aliphatic hydrocarbons, and substituted aromatic hydrocarbons.

[0079] At least one of the organic groups can further contain one or more terminal or omega functional groups that are hydrophobic. Examples of terminal or omega functional groups include carboxyl (e.g., carboxylic acid), hydroxyl, amino, imino, amide, thio and phosphonic acid, cyano, sulfonate, carbonate, and mixed substituents.

[0080] Representative examples of organic phosphoric acids or derivatives are aminotrismethylenephosphonic acid, aminobenzylphosphonic acid, 3-aminopropylphosphonic acid, O-aminophenylphosphonic acid, 4-methoxyphenylphosphonic acid, aminophenylphosphonic acid, aminophosphonobutyric acid, aminopropylphosphonic acid, benzhydrylphosphonic acid, benzylphosphonic acid, butylphosphonic acid, carboxyethylphosphonic acid, diphenylphosphonic acid, dodecylphosphonic acid, ethylidene diphosphonic acid, heptadecylphosphonic acid, methylbenzylphosphonic acid, naphthylmethylphosphonic acid, octadecylphosphonic acid, octylphosphonic acid, pentylphosphonic acid, phenylphosphinic acid, phenylphosphonic acid, styrenephosphonic acid, and dodecylbis-1,12-phosphonic acid.

[0081] In addition to monomeric organophosphates and derivatives, oligomeric or polymeric organophosphate derivatives resulting from the self-condensation of the respective monomeric acids can be used.

[0082] The hydrophobic and / or oleophobic surface modification treatment may contain fluorine. In one embodiment, the hydrophobic and / or oleophobic surface modification treatment contains a fluorine-containing moiety having a number average molecular weight of less than 2000. A preferred fluorinated material has the structure F-(CFY-CF2) m -CH2-CH2-OH, where Y is F or C. n F 2n+1 where m is 4 to 20 and n is 1 to 6. More preferred fluorinated materials are those having the structure R f -(CH2) p -X, wherein R f is a perfluoroalkylene ether group or a perfluorinated alkyl group such as those described above, p is an integer from 0 to 18, preferably from 0 to 4, and X is a carboxyl group, preferably a carboxylic acid ester group containing 1 to 50, preferably 2 to 20, carbon atoms in the alkyl group associated with the ester linkage.

[0083] In another embodiment, the organic acid of the hydrophobic and / or oleophobic surface modifier is a phosphoric acid, phosphonic acid, phosphinic acid, or sulfonic acid having from 1 to about 30 acid groups. In one embodiment, the number average molecular weight of the phosphoric acid, phosphonic acid, phosphinic acid, or sulfonic acid is from about 100 g / mol to about 5,000 g / mol.

[0084] In one embodiment, the hydrophobic and / or oleophobic surface modifier has the formula R f -(D) p -Z, where Z is an organic acid moiety and D is -CH or (OE) p group, E is a C1-C3 alkylene group, and R fis a perfluorinated alkyl group or contains a perfluorinated alkylene ether group, particularly a perfluorinated alkyl group or a perfluorinated alkylene ether group referred to herein, and p is 2 to 4.

[0085] In one embodiment, the surface modification treatment comprises the moiety R f -(CH2) p -, wherein R f is a perfluorinated alkyl group or contains a perfluorinated alkylene ether group, and p is 2 to 4, preferably 2.

[0086] Further examples of perfluorinated groups for fluorine-containing moieties are those of the following structures:

[0087] [ka] In the formula, Y is F or C n F 2n+1 where m is 4 to 20 and n is 1 to 6.

[0088] Preferred oligomeric or perfluoroalkylene ether groups are those in which R and / or R″ are groups of the structure:

[0089] [ka] In the formula, A is an oxygen atom or a chemical unit such as -CF2, n is 1 to 20, preferably 1 to 6, and Y is H, F, C n H 2n+1 , or C n F 2n+1 wherein X is H or F, b is at least 1, preferably 2 to 10, m is 0 to 50, and p is 1 to 20.

[0090] In a preferred embodiment, the surface modification treatment agent has the formula R f -CH 2p-Z, where Z, the site of attachment of the treating agent to the nanoparticle surface, is H, F or an acid derivative, and the hydrophobic and / or oleophobic moiety (attached to the surface of the nanoparticle) is R f -(CH2) p moiety, wherein R f is a perfluorinated alkyl group or contains the above-mentioned perfluorinated alkylene ether group; and p is 2 to 4, preferably 2.

[0091] In another embodiment, the surface modification treatment has the formula R f- (CH2) p -Z, wherein Z is:

[0092] [ka] As referenced above, in preferred embodiments, R and R" can independently be hydrocarbon or substituted hydrocarbon radicals having up to 200 carbons, e.g., 1 to 30 and 6 to 20 carbons, and R and R" can also include perfluoroalkyl groups as described above, and R' is H, a metal, e.g., potassium or sodium, or an amine or an aliphatic radical, e.g., alkyl, including substituted alkyl, having 1 to 50 carbons, preferably lower alkyl, having 1 to 4 carbons, e.g., methyl or ethyl, or aryl, including substituted aryl, having 6 to 50 carbons.

[0093] In one embodiment, the surface modification treatment has the formula CF3(C n F 2n )CH2CH2PO3H2, (wherein n is 3 to 5), or CF3(CF2) x O(CF2CF2) y -CH2CH2-PO3H2 (wherein x is 0 to 7, y is 1 to 20, and x+y is 27 or less).

[0094] In another embodiment, the organosilicon-containing material may be a silane, polysiloxane, or polysilazane. In one embodiment, the organosilicon-containing compound may be an organo(poly)siloxane or organo(poly)silazane having a molecular weight of at least 400, typically 1000 to 5,000,000.

[0095] Examples of organosilicon materials are alkoxysilanes and acidic compounds with branched or unbranched alkyl groups.

[0096] Suitable organosilicon-containing materials further include those of the formula R 1 4-x SiA x or (R 1 3Si) y B, as well as organo(poly)siloxanes and organo(poly)silazanes containing units of the formula:

[0097] [ka] In the formula, R 1 are hydrocarbon groups which may be the same or different and contain 1 to 100, for example 1 to 20, carbon atoms, and 1 to 12, preferably 1 to 6 carbon atoms; R 3 may be hydrogen or a hydrocarbon or substituted hydrocarbon having 1 to 12, preferably 1 to 6, carbon atoms. 1 may be a substituted hydrocarbon group such as a halo, especially a fluoro, substituted hydrocarbon group. The organo(poly)siloxane may be a substituted hydrocarbon group of the formula: R 5 2SiO2 (where R 5 may further contain additional units of (wherein is a halogen, such as a chloro or fluoro substituent).

[0098] R 1 4-x SiA x The substituent A in 2 or

[0099] [ka] may be. Formula (R 1 3Si) y B in B is NR 3 3-y R may be 2 R may be a hydrocarbon or substituted hydrocarbon group containing 1 to 12, typically 1 to 4, carbon atoms. 3 is hydrogen or R 1 where x is 1, 2, or 3 and y is 1 or 2.

[0100] Preferably, R 1 is a fluoro-substituted hydrocarbon. Such fluoro-substituted hydrocarbons are preferably those having the following structure:

[0101] [ka] In the formula, Y is F or C n F 2n+1 m is 4 to 20, n is 1 to 6, and R 2 is alkyl containing 1 to 4 carbon atoms, and p is 0 to 18. The fluoro-substituted hydrocarbon may also have the following structure:

[0102] [ka] In the formula, A is an oxygen atom or a chemical unit, n is 1 to 6, and Y is F or C. n F 2n where b is at least 1, for example, 2 to 10; m is 0 to 6; and p is 0 to 18.

[0103] Preferred organosilicon materials include halogenated siloxanes, halogenated alkoxysiloxanes such as perfluoroalkoxysiloxanes (PFOSi), alkoxyhalogenated alkoxysilanes such as alkoxy-perfluoroalkoxysilanes, alkoxyacetylacetonate-perfluoroalkoxysiloxanes, alkoxyacetylacetonate-halogenated polysiloxanes such as alkoxy-alkylsilyl halides, polyalkylsiloxanes such as polydimethylsiloxanes, and alkoxyacetylacetonate-polyalkylsiloxanes such as alkoxyacetylacetonate (acac) polydimethylsiloxanes. Exemplary surface modification treatment agents include tantalum halide-perfluoroalkoxysiloxane such as TaCl5:PFOSi; tantalum alkoxy-perfluoroalkoxysilane, tantalum alkoxyacetylacetonate-perfluoroalkoxysiloxane such as Ta(EtO)4acac:PFOSi; tantalum alkoxy-alkylsilyl halide, tantalum halide-polyalkylsiloxane such as TaCl5:PDMS; niobium alkoxide-perfluoroalkoxysiloxane such as Nb(EtO)5, PFOSi and Ta(EtO)5:PFOSi; Examples include titanium alkoxide-perfluoroalkoxysiloxane:PFOSi such as i(n-BuO)4; zirconium alkoxide-perfluoroalkoxysiloxane, lanthanum alkoxide-perfluoroalkoxysilane:PFOSi such as La(iPrO)3; tungsten chloride-perfluoroalkoxysiloxane:PFOSi such as WCl6; tantalum alkoxide-polyalkylsiloxane:PDMS such as Ta(EtO)5; and tantalum alkoxyacetylacetonate-polyalkylsiloxane:PDMS such as Ta(EtO)4acac.

[0104] In one embodiment, the fluorinated hydrocarbon is R f -(CH2) p -X, where R fis a perfluorinated hydrocarbon group containing an oxygen-substituted hydrocarbon group such as a perfluorinated alkyl group or a perfluorinated alkylene ether group; p is 0 to 18, preferably 0 to 4; X is a polar group such as the structure -(C=O)-OR, where a is carboxyl; and R is hydrogen, perfluoroalkyl, alkyl or substituted alkyl containing 1 to 50 carbon atoms.

[0105] An example of a perfluoroalkyl group is the structure F-(CFY-CF2) m wherein Y is F or C n F 2n+1 where m is 4 to 20 and n is 1 to 6.

[0106] Examples of perfluoroalkylene ether groups are those of the following structures:

[0107] [ka] In the formula, A is an oxygen atom or a chemical unit, n is 1 to 6, and Y is F or C. n F 2n wherein b is 2 to 20, m is 0 to 6, and p is 0 to 18, preferably 2 to 4, and more preferably 2.

[0108] In an exemplary embodiment, the nanoparticles are derivatized to contain amine groups by amination, where amination can be achieved by nitration followed by reduction, or by nucleophilic substitution of a leaving group with an amine, substituted amine, or protected amine, followed by deprotection as needed. In another embodiment, the nanoparticles are derivatized by oxidation methods using peroxides to generate epoxy, hydroxy, or glycol groups, or by cleavage of double bonds by metal-mediated oxidation, such as permanganate oxidation, to form ketone, aldehyde, or carboxylic acid functional groups.

[0109] When the functional group is alkyl, aryl, aralkyl, alkaryl, functionalized polymeric or oligomeric group, or a combination of these groups, the functional group may be attached to the derivatized nanoparticles directly through an intermediate functional group (e.g., carboxy, amino) or by a carbon-carbon bond without an intervening heteroatom, providing the derivatized nanoparticles with greater thermal and / or chemical stability through a carbon-oxygen bond (if the nanoparticles contain oxygen-containing functional groups such as hydroxy or carboxylic acid) or a carbon-nitrogen bond (if the nanoparticles contain nitrogen-containing functional groups such as amine or amide). In one embodiment, the nanoparticles may be derivatized by a metal-mediated reaction with a C6-30 aryl or C7-30 aralkyl halide (F, Cl, Br, I) in a carbon-carbon bond-forming step.

[0110] In another embodiment, nanoparticles such as fullerenes, nanotubes, nanodiamonds, or nanographenes can be directly metallated by reaction with an alkali metal, such as lithium, sodium, or potassium, followed in a carbon-carbon bond-forming step by reaction with a C1-30 alkyl or C7-30 alkaryl compound bearing a leaving group such as a halide (Cl, Br, I) or other leaving group (e.g., tosylate, mesylate, etc.). The aryl or aralkyl halide, or alkyl or alkaryl compound, can be substituted with functional groups such as hydroxy, carboxy, ether, etc. Exemplary groups include, for example, hydroxy groups, carboxylic acid groups, alkyl groups such as methyl, ethyl, propyl, butyl, pentyl, hexyl, octyl, dodecyl, and octadecyl; aryl groups such as phenyl and hydroxyphenyl; alkaryl groups such as benzyl groups bonded through an aryl moiety such as 4-methylphenyl, 4-hydroxymethylphenyl, or 4-(2-hydroxyethyl)phenyl (also known as phenethyl alcohol) groups; or aralkyl groups bonded to the benzyl (alkyl) position, as in phenylmethyl or 4-hydroxyphenylmethyl groups, or the 2-position of a phenethyl or 4-hydroxyphenethyl group. In an exemplary embodiment, the derivatized nanoparticle is nanographene substituted with benzyl, 4-hydroxybenzyl, phenethyl, 4-hydroxyphenethyl, 4-hydroxymethylphenyl, or 4-(2-hydroxyethyl)phenyl.

[0111] In another embodiment, the nanoparticles can be further derivatized by grafting certain polymer chains onto the functional groups. For example, polymer chains such as acrylic chains bearing carboxylic acid, hydroxy, and / or amine functional groups; polyamines, such as polyethyleneamine or polyethyleneimine; and poly(alkylene glycols), such as poly(ethylene glycol) and poly(propylene glycol), can be included by reaction with the functional groups.

[0112] When the nanoparticles are pumped into a well in an aqueous fluid, they can acquire an electrical charge, which generates an electrical potential in the dispersion, also known as the zeta potential. The zeta potential of the dispersion can be varied to control the viscosity of the fluid pumped into the well. The viscosity of the fluid can be controlled by increasing or decreasing the zeta potential.

[0113] In one embodiment, aqueous fluids may be pumped into a well as part of a stimulation operation, such as hydraulic fracturing, acid stimulation, steam injection, and thermal injection. For example, a gelling fluid may be introduced into a well after stimulation (hydraulic fracturing or acidization). The gelling fluid forms a fluid barrier across one zone in the formation, diverting subsequently introduced fluids to one or other zones. In one embodiment, the gelling fluid forms a fluid-permeable barrier across a high-permeability (or intact) zone, diverting subsequently pumped fluids to zones of lower permeability. Because conductivity is permeability multiplied by the injection geometry, this is equivalent to stating that a gelling plug can divert subsequently pumped fluids from high-conductivity primary fractures to low-conductivity secondary fractures.

[0114] Aqueous fluids can also be used to isolate production zones in wells with multiple production zones. After the formation is fractured to form a perforated production zone, aqueous fluids can be introduced into the fractured, perforated production zone. The perforated production zone can then be isolated by gelling the fluid. If desired, another production zone in the well can be drilled and the process repeated.

[0115] In another embodiment of the invention, the aqueous fluid described herein can be introduced into a predetermined targeted production zone of a well containing multiple production zones. The fluid in the predetermined targeted production zone can then be hardened, thereby isolating the predetermined targeted production zone from other zones in the well. Now that the predetermined targeted zone is sealed from the other zones, it may then be drilled and subjected to hydraulic fracturing.

[0116] Aqueous fluids can also be used as fluid loss control additives in drilling or completion operations. Loss of drilling mud into permeable zones of the formation or into the wellbore can dramatically increase costs due to fluid loss into the formation, damage to the drill bit caused by overheating, reduced drilling rates, or blowouts due to reduced fluid levels in the well. In some instances, loss of mud and / or completion fluid into the formation and / or well can cause formation collapse in the wellbore and deep blockage of the formation. This, in turn, can cause widespread damage, such that the reservoir must be abandoned. Use of aqueous fluids described herein can stop or slow the loss of drilling mud into the formation or wellbore by blocking the flow paths causing such loss. Aqueous fluids can act as lost circulation control agents (LCMs) by bridging or blocking leakage of drilling mud into the formation. Aqueous fluids may be added to drilling mud as fluid loss pills, for example, to reduce mud loss into porous, permeable formations. Additionally, if fluid loss is detected during drilling operations, the pumping of mud into the well can be stopped and then aqueous fluid can be pumped into the well to form a permeable plug in the targeted zone of the well where loss of mud into the formation or wellbore was detected.

[0117] Additionally, the aqueous fluids described herein can be used during cementing operations in which a cementitious slurry is pumped into the annulus between the exterior of the casing / liner (placed in the wellbore after drilling) and the wellbore. The cementitious slurry, upon hardening, holds the casing / liner in place. The cementitious slurry can also be used to cement pipes or casing in oil wells, injection wells, disposal wells, and storage wells, as well as oil and gas wells. In addition to selectively isolating certain areas of a wellbore from other areas of the wellbore, the cementitious slurry can also be used for other purposes. For example, cement can be used during well abandonment, such as sealing the interior of a wellbore. Furthermore, cement can be used in remediation operations to repair casing and / or achieve formation isolation, as well as in sealing perforations, repairing casing leaks (including leaks from damaged areas of the casing), plugging or sealing the bottom of a wellbore, etc.

[0118] A common problem in well cementation is the loss of liquid fluid from the cementitious slurry into the porous region in the formation surrounding the well annulus. Additionally, gas migration is a concern after the cementitious slurry is placed in the formation. Fluid loss (liquid and / or gas) is undesirable because it can lead to dehydration of the cementitious slurry. Furthermore, it can cause the formation of a thick filter cake of cement solids. Such a filter cake can plug the wellbore. Furthermore, fluid loss can damage sensitive formations. Therefore, minimal fluid loss is desirable to provide better zone isolation and minimize formation damage due to fluid intrusion. Water-based fluids serve as LCM additives (including gas control additives) for oil, gas, and water wells. Water-based fluids can be added to cementitious slurries, for example, as fluid loss pills, to reduce fluid loss (and gas migration) from the slurry into porous, permeable formations by forming a fluid-impermeable plug. Additionally, if fluid loss is detected during the cementing operation, pumping of the cementitious slurry into the well can be stopped and then an aqueous fluid can be pumped into the well to form a permeable plug in the targeted zone of the well where fluid loss was detected. [Example]

[0119] Example 1. An encapsulated crosslinker composition was prepared by first shaking a mixture of 5 ml of toluene and 50 mg of lecithin at 200 rpm for 1 minute. The mixture was then added to 25 ml of acetone and 100 mg of sorbitan monolaurate surfactant. The mixture was then shaken at 200 rpm for another 1 minute to obtain Solution 1. Solution 2 was prepared by mixing 50 ml of water with 250 ml of polysorbate surfactant. The mixture was then introduced into 50 ml of chromium(III) acetate solution (containing 11.2-11.8% chromium). Solution 1 was then slowly added dropwise to Solution 2 at a rate of 2 ml / 30 seconds. After all of Solution 1 had been added, the mixture was stirred at 150 rpm at room temperature for 24 hours. Dynamic light scattering (DLS) was used to measure particle size and estimate the distribution of microparticles in the encapsulated crosslinker composition. Figure 1 shows the normalized diameter distribution of the chromium acetate crosslinker.

[0120] Example 2. Aqueous fluids were prepared from partially hydrolyzed poly(acrylamide) (HPAM) (10,000, 15,000, 20,000, and 30,000 ppm), alumina nanoparticles (250-750 ppm), and encapsulated crosslinker. The crosslinker to polymer ratio was 1:20. The rheological properties of the solutions were measured by a rheometer (Malvern Kinexus Pro rotational rheometer) before and after heating. The apparent viscosity was measured at temperatures of 25°C and 90°C, and at 100 s. -1 Figure 2 shows the viscosity profile over time at ambient temperature for a solution prepared with 3,000 ppm HPAM, 750 ppm alumina, and a crosslinker / polymer ratio of 1:20.

[0121] Figures 3, 4, and 5 show the viscosity profiles of solutions measured at 100 / s rpm at temperatures of 25°C, 40°C, and 90°C, respectively, using solutions containing 30,000 ppm HPAM, 750 ppm alumina nanoparticles, and a 1:20 weight ratio of encapsulated crosslinker to polyacrylamide.

[0122] The viscosity versus time (gel time) of the polymer solutions was also measured at temperatures of 25° C. and 90° C. and a shear rate of 100 S / l. Figures 6 and 7 show the viscosity profiles of encapsulated crosslinker containing different amounts of HPAM (to illustrate the optimized concentration), specifically HPAM (10,000 ppm, 15,000 ppm, 20,000 ppm, or 30,000 ppm); 250 ppm alumina, and a 1:20 encapsulated crosslinker / polyacrylamide weight ratio, at 25° C. and 90° C., respectively, at 100 / s rpm.

[0123] Example 3. Aqueous fluids were prepared from 15,000 ppm HPAM, 250 ppm alumina oxide nanoparticles, and 50 mL of chromium(III) acetate solution (containing 11.2-11.8% chromium) with or without encapsulated crosslinker. The crosslinker:polyacrylamide weight ratio was 1:20. Figure 8 shows the viscosity profiles of the encapsulated versus unencapsulated crosslinker at 90°C and 100 rpm.

[0124] Examples 1, 2, and 3 demonstrate the sustained release of crosslinker into polyacrylamide-containing fluids using an encapsulated chromium acetate crosslinker. The delayed release allows the polyacrylamide to remain in a low-viscosity liquid form for extended periods at elevated temperatures. The release of the crosslinker is demonstrated to be temperature dependent. Here, crosslinker release begins at 90°C. The delayed-release crosslinker then reacts with the polyacrylamide, increasing the viscosity of the fluid and forming a occlusive gel. For example, Figure 6 shows that a fluid containing 15,000 ppm HPAM delays the crosslinker's crosslinking time, resulting in a target viscosity after the fluid reaches 90°C.

[0125] Example 4. A fluid containing 15,000 ppm HPAM, 250 ppm alumina nanoparticles, and an encapsulated crosslinker composition with a crosslinker to polyacrylamide weight ratio of 1:20, as shown in Figure 6, was evaluated in a porous media testing apparatus exhibiting properties similar to those found in geothermal wells. The apparatus consisted of a containment subsystem (porous media), a fluid exchanger cylinder, and a constant pressure pump. The injection subsystem consisted of an exchanger cylinder and a positive displacement pump. Additionally, a pore pressure subsystem was included with a pressure pump that allowed flow only at a pressure defined as the pore pressure. Table I summarizes some properties and operating conditions of the porous media used. Figure 9 shows a schematic diagram of the equipment configuration.

[0126] [Table 1]

[0127] The initial permeability was measured by heating the apparatus to 300°C and injecting saline containing 2 wt% NaCl at a flow rate of 5 cc / min. 50 mL of each gel sample (crosslinked and encapsulated polymer sample) was then injected into the porous media at the same flow rate (5 cc / min). The setup was allowed to rest for two days at 300°C and two different delta pressures: 1,000 and 2,000 psi, respectively. After two days, brine was reinjected into the porous media at a flow rate of 5 cc / min. Pressure data was recorded versus time to evaluate the thermal resistance and barrier efficiency of the gel samples.

[0128] Figure 10 shows the solution providing temporary barrier properties in the defined core (Table I), confirming that the formulation provides temporary barrier properties in the selected core. This establishes that the fluid can withstand a pressure differential (DP) of 2,000 psi at 300°C and returns to its liquid state after 2-3 days. (After 2-3 days, the DP begins to drop, indicating that the fluid breaks down and returns to its liquid state.)

[0129] Examples 5-7. These examples illustrate the effect of various retarders on the gelation time of a 22 million dalton molecular weight polyacrylamide gel. An aqueous fluid was prepared by mixing 15,000 ppm of partially hydrolyzed poly(acrylamide) with water and 250 ppm of aluminum oxide nanoparticle solution with stirring, then gradually adding 10-20 gpt of crosslinking retarder with stirring, followed by 5 gpt of chromium(III) acetate solution (containing 11.2-11.8% chromium). Table I summarizes the ingredients for each example.

[0130] [Table 2]

[0131] The effect of the retarder on gel time was determined by recording the steady shear viscosity. The gel time was determined when a significant change in the viscosity-time curve was observed. The initial measurement was 100 seconds at 25°C. -1The shear rate was then increased to 120°C, and the viscosity was recorded over time. -1 and 120°C for 1 to 4 hours, and the viscosity was recorded over time using a Chandler Model 5550 HPHT viscometer.

[0132] The graph in Figure 11 shows the viscosity profile of an aqueous fluid containing an ethoxylated sugar (CLD-X) as a crosslinking retarder. Figure 11 shows that the ethoxylated sugar effectively retards crosslinking up to a temperature of 105°C, above which the fluid begins to crosslink and form a gel.

[0133] The graph in Figure 12 demonstrates the different effects compared to fluids containing an amino acid compound (CLD-Y) as a crosslinking retarder. When using a concentration of 5 gpt, the gelling solution containing the amino acid compound formed a gel at a lower temperature of 84°C, as shown in Figure 12. This indicates that the retardation ability of the aqueous fluid containing the amino acid compound is less effective than that of the fluid containing the alkoxylated sugar. Neither the fluid containing the alkoxylated sugar nor the fluid containing the amino acid compound was able to meet the requirement of extending the gel time to 2 hours at a high temperature of 120°C.

[0134] Figure 13 shows aqueous fluids with various concentrations of metal lactate (CLD-Z) as a crosslinking retarder. As shown, at a crosslinking retarder concentration of 5 gpt, the gel solution maintained its initial viscosity for 15 minutes at 120°C. By increasing the concentration of metal lactate to 10 gpt, the gelation period was extended, allowing the solution to maintain a lower viscosity for a longer time (2 hours) at 120°C. Figure 13 shows a phase of constant viscosity followed by a sudden increase, indicating the onset and progression of gelation. Figure 13 further demonstrates that fluids containing metal lactate as a crosslinking retarder effectively delayed gelation, making them suitable for use in geothermal wells and high-temperature environments. Note that at 10 gpt, the inclusion of metal lactate significantly extended the gelation time to 2 hours. Increasing the concentration of the crosslinking retarder further extended this time. For example, with metal lactate, increasing the concentration above 10 gpt delayed gelation for more than 2 hours at 120°C. Furthermore, the 20 gpt concentration maintained fluid viscosity without gelation at 150°C, as shown in Figure 14. Figure 14 further illustrates that fluids containing polyacrylamide at concentrations of 5,000, 10,000, and 15,000 ppm exhibited different behavior in viscosity change with temperature. For example, at 10,000 and 15,000 ppm, a decrease in viscosity was observed as the temperature increased to 120°C. In particular, at 15,000 ppm, when the temperature increased above 120°C, the subsequent increase in viscosity led to gel formation. In contrast, at 5,000 ppm, gelation occurred, but its onset was delayed.

[0135] Example 8. This example illustrates the dynamic properties of aqueous fluids defined by the present invention using static testing using an HPHT cell defined by high pressure (1,000 psi) and high temperature (200°C) conditions. Such conditions simulated those in geothermal wells. The primary objective was to evaluate two important aspects: a) the polymer's stability, effectiveness in sequestration, and duration of effective sequestration at extreme geothermal temperatures ranging from 150 to 250°C (302 to 482°F), and b) the fluid's decomposition characteristics for simplified cleanup without reliance on external breakers.

[0136] Aqueous fluids were prepared by mixing 15,000 ppm of partially hydrolyzed poly(acrylamide) with a molecular weight of 22 million daltons in water while stirring a solution containing 250 ppm aluminum oxide nanoparticles with a crystallite size of 10–20 nm. Then, while stirring, gradually adding 10 μL of sodium DL-lactate crosslinking retarder, followed by 5 μL of chromium(III) acetate solution (containing 11.2–11.8% chromium). 150–200 mL of fluid was introduced into the HPHT cell, and the sample was subsequently heated to the desired temperature of 200 °C under 1,000 psi pressure. The duration of each test varied from 1 to 7 days, allowing for comprehensive observation of the fluid's behavior over time. After each test period, the HPHT cell was cooled to a safe handling temperature, carefully opened, and the fluid collected for analysis and recording.

[0137] In total, approximately 30 tests were conducted, covering a wide range of temperatures and durations. During testing at 200°C and 1,000 psi, the polymer fluid exhibited significant phase changes over several days under controlled conditions. Initially, after one day of testing, the fluid underwent transformation to a gel phase without the presence of water. This state persisted until the second day, during which the onset of crosslinking within the gel was observed. By the third day, a noticeable change occurred, as some water began to separate from the fluid, with approximately 80% still remaining in the gel phase. This transition became more pronounced on the fourth day, with the fluid converting primarily to water, although some residual gel fragments were still present. By the sixth day, the transformation was complete, with the fluid completely converted to water and no observable gel phase remaining. These observations highlight the dynamic nature of polymer fluids under prolonged exposure to high temperatures and pressures, demonstrating a clear progression from a gel phase to a fully liquid state over time. The fluid transition over the duration of the test is shown in Figure 15.

[0138] Example 9. This example illustrates the stability and performance of the aqueous fluid of Example 8 when exposed to extreme thermal conditions of 250°C. A fluid sample was introduced into a pressure cure chamber. The sample was heated to 250°C and maintained under a pressure of 1,000 psi for a duration of 24 hours. The chamber was then cooled and the fluid properties were examined. Figure 16 shows a visual comparison of the fluid sample before and after 24 hours of exposure to high temperature and pressure. Notably, the results show that the majority of the sample remained in the gel phase, suggesting a high level of thermal and pressure stability of the fluid. Examples 8 and 9 demonstrate the ability of the aqueous fluid to withstand extreme geothermal conditions and its application for temporary isolation in geothermal wells.

[0139] Embodiment 1. A method of increasing fluid productivity from a subterranean formation penetrated by a well, comprising pumping an aqueous fluid into the well, the aqueous fluid comprising: (i) nanoparticles; (ii) polyacrylamide having a weight average molecular weight of about 1.5 million to 22 million daltons; (iii) an encapsulated liquid cross-linking agent.

[0140] Embodiment 2. A method for increasing productivity of a production well, comprising: (a) pumping an aqueous fluid into a well, the fluid comprising: (i) nanoparticles; (ii) polyacrylamide having a weight average molecular weight of about 1.5 million to 22 million daltons; (iii) an encapsulated liquid cross-linking agent; (b) releasing the encapsulated cross-linking agent when the downhole temperature in the well is at least 85°C and forming a viscous fluid from the interaction of the nanoparticles, polyacrylamide, and the cross-linking agent; (d) transporting the viscous fluid to a target zone within the well to form a barrier plug relative to the target zone; (e) blocking the flow of subsequently pumped fluid to the target zone with a barrier plug while the downhole temperature in the well is at least 125°C; (f) diverting the subsequent second fluid flow to one or more second zones within the formation, the permeability of the one or more second zones being less than the permeability of the target zone.

[0141] Embodiment 3. A method for increasing productivity of a production well, comprising: (a) pumping an aqueous fluid into a well, the fluid comprising: (i) nanoparticles; (ii) polyacrylamide having a weight average molecular weight of about 1.5 million to 22 million daltons; (iii) an encapsulated liquid cross-linking agent; (b) releasing the encapsulated cross-linking agent when the downhole temperature in the well is at least 85°C and forming a viscous fluid from the interaction of the nanoparticles, polyacrylamide, and the cross-linking agent; (d) transporting the viscous fluid to a target zone within the well to form a barrier plug relative to the target zone; (e) blocking the flow of subsequently pumped fluid to the target zone with a barrier plug while the downhole temperature in the well is at least 125°C; (f) diverting the subsequent second fluid flow to one or more second zones within the formation, the permeability of the one or more second zones being less than the permeability of the target zone.

[0142] Embodiment 4. The method of embodiment 2, wherein the viscous fluid is formed in the well at a downhole temperature of 90°C or greater.

[0143] Embodiment 5. The method of embodiment 2 or 3, wherein fluid flow to the target zone is blocked by the barrier plug for a period of about 2 hours to about 2 weeks.

[0144] Embodiment 6. The method of embodiment 2 or 3, wherein fluid flow to the target zone is blocked by the barrier plug for a period of at least 72 hours.

[0145] Embodiment 7. The method of embodiment 2 or 3, wherein fluid flow to the target zone is blocked by the barrier plug for a period of about 8 hours to about 48 hours.

[0146] Embodiment 8. The method of any of embodiments 1-7, wherein the well or reservoir is a geothermal well.

[0147] Embodiment 9. The method of any of embodiments 1-7, wherein the well or reservoir is a gas well or an oil well.

[0148] Embodiment 10. A method of stimulating a subterranean formation penetrated by a geothermal well, the method comprising: (a) In the well, (i) nanoparticles; (ii) polyacrylamide having a weight average molecular weight of about 1.5 million to 22 million daltons; (iii) introducing a first aqueous fluid comprising an encapsulated liquid cross-linking agent; (b) gelling the aqueous fluid to form a plug in the target zone within the formation, the plug constituting a fluid-impermeable barrier at downhole temperatures of 125°C or greater for a period of 1 hour to 2 weeks; (c) pumping one or more second fluids into the geothermal well; (d) diverting one or more second fluid streams from the target zone to one or more second zones, wherein the permeability of the target zone is higher than the permeability of the one or more second zones.

[0149] Embodiment 11. A method for improving productivity of a hydrocarbon-bearing formation penetrated by a well having a plurality of production zones, comprising: (a) In a given production zone of a well (i) nanoparticles; (ii) polyacrylamide having a weight average molecular weight of about 1.5 million to 22 million daltons; (iii) introducing a first aqueous fluid comprising an encapsulated liquid cross-linking agent; forming a viscous gel at a temperature in the well of at least 85°C; (b) isolating a given production zone from other production zones within the well by hardening the viscous gel; (c) perforating an isolated predetermined production zone; (d) stimulating the perforated, isolated, predetermined production zone by introducing a stimulation fluid into the perforated, isolated, predetermined production zone at a pressure sufficient to fracture the perforated, isolated, predetermined production zone, wherein the temperature within the well is at least 125°C and the stimulation of the perforated, isolated, predetermined production zone is for a period of from 1 hour to 2 weeks.

[0150] Embodiment 12. A method for increasing productivity of a subterranean formation having multiple production zones, comprising: (a) drilling and fracturing a target zone within a formation, followed by introducing an aqueous fluid into the target zone, the aqueous fluid comprising: (i) nanoparticles; (ii) polyacrylamide having a weight average molecular weight of about 1.5 million to 22 million daltons; and (iii) an encapsulated liquid cross-linking agent; (b) isolating a non-stimulated zone of the well from the target zone by gelling the fluid and forming a temporary plug in the fractured target zone.

[0151] Embodiment 13. The polyacrylamide is

[0152] [ka] and the structural formula is 13. The method of any of embodiments 1-12, wherein the molar ratio of m:n is from about 5:95 to about 95:5.

[0153] Embodiment 14. The method of any one of embodiments 1 to 13, wherein the polyacrylamide is a powder.

[0154] Embodiment 15. The method of any of embodiments 1-13, wherein the polyacrylamide is in an emulsion or oil slurry.

[0155] Embodiment 16 The method of any of embodiments 1-13, wherein the polyacrylamide comprises microbeads having a diameter of about 0.5 to 2.0 microns.

[0156] Embodiment 17. The method of any of embodiments 1-16, wherein the polyacrylamide has a weight average molecular weight of about 5 million to about 20 million daltons.

[0157] Embodiment 18. The method of embodiment 17, wherein the polyacrylamide has a weight average molecular weight of about 6 million to about 8 million daltons.

[0158] Embodiment 19. The method of any of embodiments 1 to 18, wherein the degree of hydrolysis of the acrylamide units of the polyacrylamide polymer is from about 0.15 to about 0.40.

[0159] Embodiment 20. The method of embodiment 19, wherein the polyacrylamide polymer has a degree of hydrolysis of the acrylamide units of from about 0.25 to about 0.35.

[0160] Embodiment 21. The method of any of embodiments 1-20, wherein the liquid crosslinker is a metal or metal complex, and the metal is chromium, titanium, aluminum, zirconium, calcium, magnesium, or zinc.

[0161] Embodiment 22 The method of embodiment 21, wherein the metal of the crosslinker is or contains chromium.

[0162] Embodiment 23 The method of embodiment 22, wherein the crosslinking agent is chromium acetate or chromium chloride.

[0163] Embodiment 24 The method of any of embodiments 1-23, wherein the crosslinker has a counterion or ligand selected from the group consisting of acetate, propionate, lactate, oxalate, malonate, maleate, succinate, glutamate, phosphonate, sulfonate, carbonate, or halide.

[0164] Embodiment 25. The method of any of embodiments 1 to 24, wherein the aqueous fluid before being gelled comprises from about 2,000 to about 20,000 ppm polyacrylamide.

[0165] Embodiment 26. The method of embodiment 25, wherein the aqueous fluid before being gelled comprises about 12,000 to about 15,000 ppm polyacrylamide.

[0166] Embodiment 27. The method of any of embodiments 1-26, wherein the nanoparticles have a number average particle diameter of less than 1000 nm.

[0167] Embodiment 28. The method of any of embodiments 1-27, wherein the nanoparticles are selected from the group consisting of silica, alumina, titania, silicic acid, aluminum oxide, aluminum hydroxide, zirconium oxide, zirconium hydroxide, zirconium hydroxide oxide, tungsten oxide, iron oxide, tungsten carbide, silicon carbide, boron carbide, titanium nitride, boron nitride, silicon nitride, fullerenes, nanographite, carbon nanotubes, antimony oxide, vanadium oxide, magnesium oxide, clay, and nanoclay.

[0168] Embodiment 29. The method of any of embodiments 1-27, wherein the nanoparticles are selected from the group consisting of alkali metals, alkaline earth metals, lanthanides, actinides or transition metals, fullerenes, nanotubes, graphene, nanodots, nanorods, nanodiamonds, polysilsesquioxanes, nanoclays, and combinations thereof.

[0169] Embodiment 30. The method of any of embodiments 1-29, wherein the nanoparticles are derivatized with a functional group selected from the group consisting of carboxy, epoxy, ether, ketone, amine, hydroxy, alkoxy, alkyl, aryl, aralkyl, alkaryl, and lactone, or a combination thereof.

[0170] Embodiment 31. The method of any of embodiments 1-29, wherein the nanoparticles are derivatized with a functional group selected from (i) organosilicon materials, (ii) fluorinated organic acids or reactive derivatives, (iii) linear or branched alkyl organic acids or reactive derivatives, (iv) substituted alkyl organic acids or reactive derivatives, (v) aryl or substituted aryl organic acids or reactive derivatives, and (vi) mixtures thereof.

[0171] Embodiment 32. A method of treating a subterranean formation penetrated by a well to increase productivity of fluids from the formation, the method comprising: (a) In the well, (i) nanoparticles; (ii) polyacrylamide having a weight average molecular weight of about 1.5 million to 22 million daltons; (iii) introducing a first aqueous fluid comprising a liquid cross-linking agent; the liquid cross-linking agent is encapsulated and / or the aqueous fluid further comprises a cross-linking retarder selected from the group consisting of metal lactate or ammonium lactate, hydroxylated glycine, and alkoxylated sugar alcohol; (b) gelling the aqueous fluid to form a plug in the target zone within the formation, the plug constituting a fluid-impermeable barrier at downhole temperatures of 85°C or greater for a period of 1 hour to 2 weeks.

[0172] Embodiment 33. The method of embodiment 32, wherein the well is a geothermal well.

[0173] Embodiment 34. The polyacrylamide is

[0174] [ka] and the structural formula is 34. The method of embodiment 32 or 33, wherein the molar ratio of m:n is from about 5:95 to about 95:5.

[0175] Embodiment 35. The method of embodiment 34, wherein the polyacrylamide is a powder in an emulsion or oil slurry, or microbeads having a diameter of about 0.5 to 2.0 microns.

[0176] Embodiment 36. The method of any of embodiments 32-35, wherein the polyacrylamide has a weight average molecular weight of about 5 million to about 20 million daltons and / or the degree of hydrolysis of the acrylamide units of the polyacrylamide polymer is about 0.15 to about 0.40.

[0177] Embodiment 37. The method of any of embodiments 32-36, wherein the liquid crosslinker is a metal or metal complex, and the metal is chromium, titanium, aluminum, zirconium, calcium, magnesium, or zinc.

[0178] Embodiment 38 The method of embodiment 37, wherein the crosslinking agent is chromium acetate or chromium chloride.

[0179] Embodiment 39. The method of any of embodiments 32-38, wherein the aqueous fluid before being gelled comprises about 2,000 to about 20,000 ppm polyacrylamide.

[0180] Embodiment 40. The method of any of embodiments 32-39, wherein the nanoparticles have a number average particle diameter of less than 1000 nm.

[0181] Embodiment 41. The method of embodiment 40, wherein the nanoparticles are selected from the group consisting of silica, alumina, titania, silicic acid, aluminum oxide, aluminum hydroxide, zirconium oxide, zirconium hydroxide, zirconium hydroxide oxide, tungsten oxide, iron oxide, tungsten carbide, silicon carbide, boron carbide, titanium nitride, boron nitride, silicon nitride, fullerenes, nanographite, carbon nanotubes, antimony oxide, vanadium oxide, magnesium oxide, clay, nanoclay, alkali metals, alkaline earth metals, lanthanides, actinides, transition metals, fullerenes, graphene, nanodots, nanorods, nanodiamonds, polysilsesquioxanes, nanoclays, and combinations thereof.

[0182] Embodiment 42. The method of any of embodiments 32-41, wherein the nanoparticles are derivatized with a functional group selected from the group consisting of carboxy, epoxy, ether, ketone, amine, hydroxy, alkoxy, alkyl, aryl, aralkyl, alkaryl, lactone, organosilicon materials, fluorinated organic acids or reactive derivatives, linear or branched alkyl organic acids or reactive derivatives, substituted alkyl organic acids or reactive derivatives, aryl or substituted aryl organic acids or reactive derivatives, and mixtures thereof.

[0183] Embodiment 43. The method of any of embodiments 32-42, wherein the nanoparticles have a number average particle size of less than 1,000 nm in diameter.

[0184] Embodiment 44. The method of any one of embodiments 32-43, wherein the cross-linking agent is encapsulated.

[0185] Embodiment 45. The method of any of embodiments 32-44, wherein the crosslinking retarder is a metal lactate or ammonium lactate.

[0186] Embodiment 46 The method of embodiment 45, wherein the lactate salt is sodium, potassium, calcium, or ammonium lactate.

[0187] Embodiment 47. The method of embodiment 46, wherein the lactate salt is sodium lactate.

[0188] Embodiment 48. The method of any of embodiments 32-47, wherein the treatment is a stimulation operation, an excavation operation, a completion operation, or a cementing operation.

[0189] Embodiment 49. The processing is a stimulation operation, (c) pumping one or more second fluids into the well; 49. The method of embodiment 48, further comprising: (d) diverting one or more second fluid streams from the target zone to one or more second zones, wherein the permeability of the target zone is higher than the permeability of the one or more second zones.

[0190] Embodiment 50. The well has multiple production zones and a downhole temperature of at least 125°C; (c) using a barrier plug to block the flow of subsequently pumped fluid to the target zone while the downhole temperature in the well is at least 125°C; 49. The method of embodiment 48, further comprising: (d) diverting the subsequent second fluid flow to one or more second zones within the formation, the permeability of the one or more second zones being less than the permeability of the target zone.

[0191] Embodiment 51. The well has multiple production zones and contains a liquid cross-linking agent; (c) isolating the predetermined production zone from other production zones in the well by hardening the viscous gel; (d) perforating an isolated predetermined production zone; 49. The method of embodiment 48, further comprising: (e) stimulating the perforated, isolated, predetermined production zone by introducing a stimulation fluid into the perforated, isolated, predetermined production zone at a pressure sufficient to fracture the perforated, isolated, predetermined production zone, wherein the temperature within the well is at least 125°C, and wherein the stimulation of the perforated, isolated, predetermined production zone is for a period of 1 hour to 2 weeks.

[0192] Embodiment 52. The processing operation is an excavation operation; 49. The method of embodiment 48, further comprising (c) circulating drilling mud in the well after forming a plug in the target zone.

[0193] Embodiment 53. The processing operation is a completion operation; (a) circulating drilling mud into the well after forming a plug in the target zone; (b) circulating completion or workover brine into the well after forming a plug in the target zone; (c) circulating a displacement pill (such as a transition spacer, wash spacer, high viscosity pill, or open hole sweep pill) within the well after forming a plug within the target zone; 49. The method of embodiment 48, further comprising (d) circulating a screening running fluid in the well after forming the plug in the target zone.

[0194] Embodiment 54. The treatment operation is a cementation operation; 49. The method of embodiment 48, further comprising: (c) pumping the cementitious slurry into the well and allowing the slurry to set.

Claims

1. 1. A method of stimulating a subterranean formation penetrated by a geothermal well, the method comprising: (a) adding to the well: (i) nanoparticles; (ii) polyacrylamide having a weight average molecular weight of about 1.5 million to 22 million daltons; (iii) introducing a first aqueous fluid comprising an encapsulated liquid cross-linking agent; (b) causing the aqueous fluid to gel and form a plug in the target zone within the formation, the plug constituting a fluid-impermeable barrier at downhole temperatures of 125°C or greater for a period of 1 hour to 2 weeks; (c) pumping one or more second fluids into the geothermal well; (d) diverting the one or more second fluid streams from the target zone to one or more second zones, wherein the permeability of the target zone is higher than the permeability of the one or more second zones.

2. The polyacrylamide 【Chemistry 1】 and the structural formula is 2. The method of claim 1, wherein the molar ratio of m:n is from about 5:95 to about 95:

5.

3. 3. The method of claim 2, wherein the polyacrylamide is a powder in an emulsion or oil slurry or microbeads having a diameter of about 0.5 to 2.0 microns.

4. 10. The method of claim 1, wherein the polyacrylamide has a weight average molecular weight of about 5 million to about 20 million daltons and / or the polyacrylamide polymer has a degree of hydrolysis of the acrylamide units of about 0.15 to about 0.

40.

5. 10. The method of claim 1, wherein the liquid cross-linking agent is a metal or metal complex, and the metal is chromium, titanium, aluminum, zirconium, calcium, magnesium, or zinc.

6. 6. The method of claim 5, wherein the cross-linking agent is chromium acetate or chromium chloride.

7. 10. The method of claim 1, wherein the aqueous fluid before being gelled comprises from about 2,000 to about 20,000 ppm of said polyacrylamide.

8. The method of claim 1 , wherein the nanoparticles have a number average particle diameter of less than 1000 nm.

9. 10. The method of claim 1, wherein the nanoparticles are selected from the group consisting of silica, alumina, titania, silicic acid, aluminum oxide, aluminum hydroxide, zirconium oxide, zirconium hydroxide, zirconium hydroxide oxide, tungsten oxide, iron oxide, tungsten carbide, silicon carbide, boron carbide, titanium nitride, boron nitride, silicon nitride, fullerenes, nanographite, carbon nanotubes, antimony oxide, vanadium oxide, magnesium oxide, clay, nanoclay, alkali metals, alkaline earth metals, lanthanides, actinides, transition metals, fullerenes, graphene, nanodots, nanorods, nanodiamonds, polysilsesquioxanes, nanoclays, and combinations thereof.

10. 10. The method of claim 1, wherein the nanoparticles are derivatized with a functional group selected from the group consisting of carboxy, epoxy, ether, ketone, amine, hydroxy, alkoxy, alkyl, aryl, aralkyl, alkaryl, lactone, organosilicon materials, fluorinated organic acids or reactive derivatives, straight or branched chain alkyl organic acids or reactive derivatives, substituted alkyl organic acids or reactive derivatives, aryl or substituted aryl organic acids or reactive derivatives, and mixtures thereof.

11. 1. A method for increasing fluid productivity from a subterranean formation penetrated by a well, comprising pumping an aqueous fluid into the well, the aqueous fluid comprising: (i) nanoparticles; (ii) polyacrylamide having a weight average molecular weight of about 1.5 million to 22 million daltons; (iii) an encapsulated liquid cross-linking agent.

12. (a) releasing the encapsulated cross-linking agent when the downhole temperature in the well is at least 85°C and forming a viscous fluid from the interaction of the nanoparticles, polyacrylamide, and cross-linking agent; transporting the viscous fluid to a target zone within the well to form a barrier plug relative to the target zone; (b) using the barrier plug to block the flow of subsequently pumped fluid to the target zone while the downhole temperature in the well is at least 125°C; 12. The method of claim 11, further comprising: (c) diverting the subsequent second fluid flow to one or more second zones within the formation, the permeability of the one or more second zones being less than the permeability of the target zone.

13. The method of claim 12 wherein the well is a geothermal well.

14. The polyacrylamide 【Chemistry 2】 and the structural formula is 13. The method of claim 12, wherein the molar ratio of m:n is from about 5:95 to about 95:

5.

15. 15. The method of claim 14, wherein the polyacrylamide is a powder in an emulsion or oil slurry or microbeads having a diameter of about 0.5 to 2.0 microns.

16. 13. The method of claim 12, wherein the cross-linking agent is chromium acetate or chromium chloride.

17. 13. The method of claim 12, wherein the nanoparticles have a number average particle size of less than 1,000 nm in diameter.

18. 1. A method for increasing productivity of a hydrocarbon-bearing formation penetrated by a well having a plurality of production zones, comprising: (a) in a predetermined production zone of said well, (i) nanoparticles; (ii) polyacrylamide having a weight average molecular weight of about 1.5 million to 22 million daltons; (iii) introducing an aqueous treatment fluid comprising an encapsulated liquid cross-linking agent; forming a viscous gel at a temperature in the well of at least 85°C; (b) isolating the predetermined production zone from other production zones within the well by hardening the viscous gel; (c) perforating said isolated predetermined production zone; (d) stimulating the perforated, isolated, predetermined production zone by introducing a stimulation fluid into the perforated, isolated, predetermined production zone at a pressure sufficient to fracture the perforated, isolated, predetermined production zone, wherein the temperature within the well is at least 125°C and the stimulation of the perforated, isolated, predetermined production zone is for a period of from 1 hour to 2 weeks.

19. The polyacrylamide 【Transformation 3】 and the structural formula is 19. The method of claim 18, wherein the molar ratio of m:n is from about 5:95 to about 95:

5.

20. 20. The method of claim 19, wherein the polyacrylamide is a powder in an emulsion or oil slurry or microbeads having a diameter of about 0.5 to 2.0 microns.

21. 1. A method for treating a subterranean formation penetrated by a well to increase fluid productivity from the formation, the method comprising: (a) adding to the well: (i) nanoparticles; (ii) polyacrylamide having a weight average molecular weight of about 1.5 million to 22 million daltons; (iii) introducing a first aqueous treatment fluid comprising a liquid cross-linking agent; the liquid cross-linking agent is encapsulated and / or the aqueous fluid further comprises a cross-linking retarder selected from the group consisting of metal lactate or ammonium lactate, hydroxylated glycine, and alkoxylated sugar alcohol; (b) allowing the aqueous fluid to gel and form a plug in a target zone within the formation, the plug constituting a fluid-impermeable barrier at downhole temperatures of 85°C or greater for a period of 1 hour to 2 weeks.

22. 22. The method of claim 21, wherein the well is a geothermal well.

23. The polyacrylamide 【Chemistry 4】 and the structural formula is 23. The method of claim 21 or 22, wherein the molar ratio of m:n is from about 5:95 to about 95:

5.

24. 24. The method of claim 23, wherein the polyacrylamide is a powder in an emulsion or oil slurry or microbeads having a diameter of about 0.5 to 2.0 microns.

25. 25. The method of any one of claims 21 to 24, wherein the polyacrylamide has a weight average molecular weight of about 5 million to about 20 million daltons and / or the polyacrylamide polymer has a degree of hydrolysis of the acrylamide units of about 0.15 to about 0.

40.

26. 26. The method of any one of claims 21 to 25, wherein the liquid cross-linking agent is a metal or metal complex, and the metal is chromium, titanium, aluminium, zirconium, calcium, magnesium or zinc.

27. 27. The method of claim 26, wherein the cross-linking agent is chromium acetate or chromium chloride.

28. 28. The method of any one of claims 21 to 27, wherein the aqueous fluid before being gelled comprises from about 2,000 to about 20,000 ppm of said polyacrylamide.

29. 29. The method of any one of claims 21 to 28, wherein the nanoparticles have a number average particle diameter of less than 1000 nm.

30. 30. The method of claim 29, wherein the nanoparticles are selected from the group consisting of silica, alumina, titania, silicic acid, aluminum oxide, aluminum hydroxide, zirconium oxide, zirconium hydroxide, zirconium hydroxide oxide, tungsten oxide, iron oxide, tungsten carbide, silicon carbide, boron carbide, titanium nitride, boron nitride, silicon nitride, fullerenes, nanographite, carbon nanotubes, antimony oxide, vanadium oxide, magnesium oxide, clay, nanoclay, alkali metals, alkaline earth metals, lanthanides, actinides, transition metals, fullerenes, graphene, nanodots, nanorods, nanodiamonds, polysilsesquioxanes, nanoclays, and combinations thereof.

31. 30. The method of any one of claims 21 to 29, wherein the nanoparticles are derivatized with a functional group selected from the group consisting of carboxy, epoxy, ether, ketone, amine, hydroxy, alkoxy, alkyl, aryl, aralkyl, alkaryl, lactone, organosilicon materials, fluorinated organic acids or reactive derivatives, linear or branched alkyl organic acids or reactive derivatives, substituted alkyl organic acids or reactive derivatives, aryl or substituted aryl organic acids or reactive derivatives, and mixtures thereof.

32. 32. The method of any one of claims 21 to 31, wherein the nanoparticles have a number average particle size of less than 1,000 nm in diameter.

33. The method of any one of claims 21 to 32, wherein the cross-linking agent is encapsulated.

34. The method of any one of claims 21 to 33, wherein the crosslinking retarder is a metal lactate or ammonium lactate.

35. 35. The method of claim 34, wherein the lactate salt is sodium, potassium, calcium, or ammonium lactate.

36. 36. The method of claim 35, wherein the lactate salt is sodium lactate.

37. The method of any one of claims 21 to 36, wherein the process is a stimulation operation, an excavation operation, a completion operation, or a cementing operation.

38. the treatment is a stimulation action; (c) pumping one or more second fluids into the well; 38. The method of claim 37, further comprising: (d) diverting the one or more second fluid streams from the target zone to one or more second zones, wherein the permeability of the target zone is higher than the permeability of the one or more second zones.

39. the well having a plurality of production zones and a downhole temperature of at least 125°C; (c) using the barrier plug to block the flow of subsequently pumped fluid to the target zone while the downhole temperature in the well is at least 125°C; 38. The method of claim 37, further comprising: (d) diverting the subsequent second fluid flow to one or more second zones within the formation, the permeability of the one or more second zones being less than the permeability of the target zone.

40. the well has a plurality of production zones and encapsulates the liquid crosslinker; (c) isolating the predetermined production zone from other production zones within the well by hardening the viscous gel; (d) perforating said isolated predetermined production zone; 38. The method of claim 37, further comprising: (e) stimulating the perforated, isolated, predetermined production zone by introducing a stimulation fluid into the perforated, isolated, predetermined production zone at a pressure sufficient to fracture the perforated, isolated, predetermined production zone, wherein the temperature within the well is at least 125°C and the stimulation of the perforated, isolated, predetermined production zone is for a period of from 1 hour to 2 weeks.

41. the processing operation is an excavation operation; 38. The method of claim 37, further comprising: (c) circulating drilling mud through the well after forming the plug in the target zone.

42. the processing operation is a completion operation; (a) circulating drilling mud into the well after forming the plug in the target zone; (b) circulating completion or workover brine into the well after forming the plug in the target zone; (c) circulating a displacement pill (such as a transition spacer, wash spacer, high viscosity pill, open hole sweep pill, etc.) within the well after forming the plug within the target zone; 38. The method of claim 37, further comprising: (d) circulating a screening running fluid in the well after forming the plug in the target zone.

43. the treatment operation is a cementation operation; 38. The method of claim 37, further comprising: (c) pumping a cementitious slurry into the well and allowing the slurry to set.

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