GELATION ACCELERATION

The invention provides a method made of steps of injecting into a wellbore, a composition comprising a solvent, a crosslinkable polymer, a crosslinking agent capable of crosslinking the polymer or forming a polymer, and a gelling accelerator selected from the group consisting of carbon dioxide, polylactic acid, encapsulated acid and latent acid; and allowing viscosity of the composition to increase and form a gel more quickly with the gelling accelerator than without.

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Description
FIELD OF THE INVENTION

This invention relates generally to the art of making and using oilfield treatment gels that viscosify more quickly. More particularly it relates to fluids made of acrylamide polymer and/or copolymer with a gelation accelerator and methods of using such fluids in a well from which oil and/or gas can be produced.

BACKGROUND

The statements in this section merely provide background information related to the present disclosure and may not constitute prior art.

Hydrocarbons (oil, condensate, and gas) are typically produced from wells that are drilled into the formations containing them. For a variety of reasons, such as inherently low permeability of the reservoirs or damage to the formation caused by drilling and completion of the well, the flow of hydrocarbons into the well is undesirably low. In this case, the well is “stimulated,” for example using hydraulic fracturing, chemical (usually acid) stimulation, or a combination of the two (called acid fracturing or fracture acidizing).

Hydraulic fracturing involves injecting fluids into a formation at high pressures and rates such that the reservoir rock fails and forms a fracture (or fracture network). Proppants are typically injected in fracturing fluids after the pad to hold the fracture(s) open after the pressures are released. In chemical (acid) stimulation treatments, flow capacity is improved by dissolving materials in the formation.

In hydraulic and acid fracturing, a first, viscous fluid called a “pad” is typically injected into the formation to initiate and propagate the fracture. This is followed by a second fluid that contains a proppant to keep the fracture open after the pumping pressure is released. Granular proppant materials may include sand, ceramic beads, or other materials. In “acid” fracturing, the second fluid contains an acid or other chemical such as a chelating agent that can dissolve part of the rock, causing irregular etching of the fracture face and removal of some of the mineral matter, resulting in the fracture not completely closing when the pumping is stopped. Occasionally, hydraulic fracturing is done without a highly viscosified fluid (i.e., slick water) to minimize the damage caused by polymers or the cost of other viscosifiers.

When multiple hydrocarbon-bearing zones are stimulated by hydraulic fracturing or chemical stimulation, it is desirable to treat the multiple zones in multiple stages. In multiple zone fracturing, a first pay zone is fractured. Then, the fracturing fluid is diverted to the next stage to fracture the next pay zone. The process is repeated until all pay zones are fractured. Alternatively, several pay zones may be fractured at one time, if they are closely located with similar properties. Diversion may be achieved with various techniques including formation of a temporary plug using polymer gels.

Polymer gels have been widely used for conformance control of naturally fissured/fractured reservoirs. For an overview of existing polymer compositions, reference is made to the U.S. Pat. Nos. 5,486,312 and 5,203,834 which also list a number of patents and other sources related to gel-forming polymers.

In an effort to reduce the cost of the gelling system without substantially diminishing the effectiveness of the treatment, attempts are known to at least partially substitute the polymer by a less expensive component. One way are foamable gel compositions as described for example in the U.S. Pat. Nos. 5,105,884, 5,203,834, and 5,513,705, wherein the polymer content is reduced at constant volume of the composition.

The typical components of a foamable gel composition are (a) a solvent, (b) a crosslinkable polymer, (c) a crosslinking agent capable of crosslinking the polymer or forming a polymer, (d) a surfactant to reduce the surface tension between the solvent and the gas, and (e) the foaming gas, itself.

The use of CO2 as foaming gas is desirable from an economic viewpoint, as this gas is used in many gas injection projects designed to generate an external fluid drive in the reservoir. Therefore an economic source of CO2 would in principle be available for the gel foaming step. However, experiments with known gel systems showed that CO2 when used as foaming gas has a considerable impact on the stability of the gelling system. When CO2 dissolves in water, it is converted to carbonic acid. It was found that known formulations for gelling systems either failed to gel in the presence of CO2 gas or resulted in a gel with reduced long-term stability.

The applicants found surprisingly that CO2 as well as other compound can be used to provide a foamable gelling composition having shorter gelling time at low temperatures.

SUMMARY

In a first aspect, a method is disclosed. The method comprises the step of injecting into a wellbore, a composition comprising a solvent, a crosslinkable polymer, a crosslinking agent capable of crosslinking the polymer or forming a polymer, and a gelling accelerator selected from the group consisting of carbon dioxide, polylactic acid (PLA), encapsulated acid and latent acid; and allowing viscosity of the composition to increase and form a gel more quickly with the gelling accelerator than without.

In a second aspect, a method of treating a subterranean formation from a wellbore is disclosed. The formation comprises a rock made of carbonates. The method comprises the step of injecting into the wellbore, a composition comprising a solvent, a crosslinkable polymer, a crosslinking agent capable of crosslinking the polymer or forming a polymer, and a gelling accelerator, wherein the gelling accelerator is substantially inert to the carbonate rock; contacting the composition with the subterranean formation, wherein the temperature is below 150 or 130 degrees Celsius (° C.) at this contact; and allows viscosity of the composition to increase and form a gel more quickly with the gelling accelerator than without.

In a third aspect, method of treating a subterranean formation from a wellbore is disclosed. The method comprises the step of injecting into a wellbore, a composition comprising a solvent, a crosslinkable polymer, a crosslinking agent capable of crosslinking the polymer or forming a polymer, a surfactant and carbon dioxide; contacts the composition with the subterranean formation, wherein the temperature is below 130° C. at this contact; and allowing viscosity of the composition to increase and form a gel more quickly with the carbon dioxide than without.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a graph comparing viscosity over time at 212° F. (100° C.) for Fluid 1 (1.25% acrylamide sodium acrylate copolymer, 0.2% hexamethylenetetramine, and 0.1% phenyl acetate) at 400 psi of N2, for Fluid 2 (1.25% acrylamide sodium acrylate copolymer, 0.2% hexamethylenetetramine, and 0.1% phenyl acetate) at 400 psi of CO2, and for Fluid 3 (1.25% acrylamide sodium acrylate copolymer, 0.2% hexamethylenetetramine, 0.1% phenyl acetate, 2% CaCO3, and 0.5% the foaming agent solution) at 400 psi of CO2, respectively.

FIG. 2 is a graph recording viscosity over time at 212° F. (100° C.) for Fluid 1 (2% sodium acrylate acrylamide copolymer dispersed in mineral oil, 0.2% hexamethylenetetramine, and 0.1% phenyl acetate) at 400 psi of CO2.

FIG. 3 is a graph comparing viscosity over time at 225° F. (107° C.) for Fluid 1 (1.25% acrylamide sodium acrylate copolymer, 0.2% hexamethylenetetramine, and 0.1% phenyl acetate) and Fluid 2 (1.25% acrylamide sodium acrylate copolymer, 0.2% hexamethylenetetramine, 0.1% phenyl acetate, and 1.2% polylactide fibers), respectively, at 400 psi of N2.

FIG. 4 is a graph comparing viscosity over time at 250° F. (121° C.) for Fluid 1 (1.25% acrylamide sodium acrylate copolymer, 0.2% hexamethylenetetramine, and 0.1% phenyl acetate) and Fluid 2 (1.25% acrylamide sodium acrylate copolymer, 0.2% hexamethylenetetramine, 0.1% phenyl acetate, and 0.6% polylactide fibers), respectively, at 400 psi of N2.

FIG. 5 is a graph comparing viscosity over time at 225° F. (107° C.) for Fluid 1 (1.25% acrylamide sodium acrylate copolymer, 0.2% hexamethylenetetramine, and 0.1% phenyl acetate) and Fluid 2 (1.25% acrylamide sodium acrylate copolymer, 0.2% hexamethylenetetramine, 0.1% phenyl acetate, 2% CaCO3 powder, and 1.2% polylactide fibers), respectively, at 400 psi of N2.

FIG. 6 is a graph comparing viscosity over time at 225° F. (107° C.) for Fluid 1 (2% sodium acrylate acrylamide copolymer dispersed in mineral oil, 0.2% hexamethylenetetramine, 0.1% phenyl acetate, and 1.2% polylactide resin) at 400 psi of N2.

 DETAILED DESCRIPTION

At the outset, it should be noted that in the development of any actual embodiments, numerous implementation-specific decisions must be made to achieve the developer's specific goals, such as compliance with system and business related constraints, which can vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time consuming but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure.

The description and examples are presented solely for the purpose of illustrating embodiments of the invention and should not be construed as a limitation to the scope and applicability of the invention. In the summary of the invention and this detailed description, each numerical value should be read once as modified by the term “about” (unless already expressly so modified), and then read again as not so modified unless otherwise indicated in context. Also, in the summary of the invention and this detailed description, it should be understood that a concentration range listed or described as being useful, suitable, or the like, is intended that any and every concentration within the range, including the end points, is to be considered as having been stated. For example, “a range of from 1 to 10” is to be read as indicating each and every possible number along the continuum between about 1 and about 10. Thus, even if specific data points within the range, or even no data points within the range, are explicitly identified or refer to only a few specific, it is to be understood that inventors appreciate and understand that any and all data points within the range are to be considered to have been specified, and that inventors possession of the entire range and all points within the range disclosed and enabled the entire range and all points within the range.

As used herewith the term “gel” means a substance selected from the group consisting of (a) colloids in which the dispersed phase has combined with the continuous phase to produce a viscous, jelly-like product, (b) crosslinked polymers, and (c) mixtures thereof.

According to a first embodiment, the gel composition is a composition made from: a solvent, a crosslinkable polymer, a crosslinking agent capable of crosslinking the polymer or forming a polymer, and a gelling accelerator.

The solvent may be any liquid in which the crosslinkable polymer and crosslinking agent can be dissolved, mixed, suspended or otherwise dispersed to facilitate gel formation. The solvent may be an aqueous liquid such as fresh water or a brine.

A crosslinked polymer is generally formed by reacting or contacting proper proportions of the crosslinkable polymer with the crosslinking agent. However, the gel-forming composition need only contain either the crosslinkable polymer or the crosslinking agent. When the crosslinkable polymer or crosslinking agent is omitted from the composition, the omitted material is usually introduced into the subterranean formation as a separate slug, either before, after, or simultaneously with the introduction of the gel-forming composition. The composition may comprise at least the crosslinkable polymer or monomers capable of polymerizing to form a crosslinkable polymer (e.g. acrylamide, vinyl acetate, acrylic acid, vinyl alcohol, methacrylamide, ethylene oxide, propylene oxide, AMPS (acrylamido-2-methylpropanesulfonic acid), and vinyl pyrrolidone). In another embodiment, the composition comprises both (a) the crosslinking agent and (b) either (i) the crosslinkable polymer or (ii) the polymerizable monomers capable of forming a crosslinkable polymer.

Typically, the crosslinkable polymer is water soluble. Common classes of water soluble crosslinkable polymers include polyvinyl polymers, polymethacrylamides, cellulose ethers, polysaccharides, lignosulfonates, ammonium salts thereof, alkali metal salts thereof, as well as alkaline earth salts of lignosulfonates. Specific examples of typical water soluble polymers are acrylamide polymers and copolymers, acrylic acid-acrylamide copolymers, acrylic acid-methacrylamide copolymers, polyacrylamides, partially hydrolyzed polyacrylamides, partially hydrolyzed polymethacrylamides, polyvinyl alcohol, polyvinyl pyrrolidone, polyalkyleneoxides, carboxycelluloses, carboxyalkylhydroxyethyl celluloses, hydroxyethylcellulose, galactomannans (e.g., guar gum), substituted galactomannans (e.g., hydroxypropyl guar), heteropolysaccharides obtained by the fermentation of starch-derived sugar (e.g., xanthan gum), and ammonium and alkali metal salts thereof. Other water soluble crosslinkable polymers include hydroxypropyl guar, partially hydrolyzed polyacrylamides, xanthan gum, diutan gum, polyvinyl alcohol, and the ammonium and alkali metal salts thereof.

The crosslinkable polymer is available in several forms such as a water solution or broth, a gel log solution, a dried powder, and a hydrocarbon emulsion or dispersion. As is well known to those skilled in the art, different types of equipment are employed to handle these different forms of crosslinkable polymers.

With respect to the crosslinking agents, these agents are organic and inorganic compounds well known to those skilled in the art. Exemplary organic crosslinking agents include, but are not limited to, aldehydes, dialdehydes, phenols, substituted phenols, hexamethylenetetramine and ethers. Phenol, phenyl acetate, resorcinol, glutaraldehyde, catechol, hydroquinone, gallic acid, pyrogallol, phloroglucinol, formaldehyde, and divinylether are some of the more typical organic crosslinking agents. Typical inorganic crosslinking agents are polyvalent metals, chelated polyvalent metals, and compounds capable of yielding polyvalent metals. Some of the more common inorganic crosslinking agents include chromium salts, aluminates, gallates, dichromates, titanium chelates, aluminum citrate, chromium citrate, chromium acetate, and chromium propionate.

The gelling accelerator may be polylactic acid (PLA) fibers or particles or other type of components which generally either hydrolyze or thermally decompose to form an acid downhole. As well, the gelling accelerator may be encapsulated acid or latent acid.

According to a second embodiment, the gel composition is a composition made from: a solvent, a crosslinkable polymer, a crosslinking agent capable of crosslinking the polymer, a surfactant and a gelling accelerator embodied as a foaming gas.

Surfactants may be used to reduce the surface tension between the solvent and the gas. The surfactants may be water-soluble and have sufficient foaming ability to enable the composition, when traversed by a gas, to foam and, upon curing, form a foamed gel. Typically, the surfactant is used in a concentration of up to about 10, about 0.01 to about 5, about 0.05 to about 3, or about 0.1 to about 2 weight percent.

The surfactant may be substantially any conventional anionic, cationic or nonionic surfactant. Anionic, cationic and nonionic surfactants are well known in general and are commercially available. Exemplary surfactants include, but are not limited to, alkyl polyethylene oxide sulfates, alkyl alkylolamine sulfates, modified ether alcohol sulfate sodium salt, sodium lauryl sulfate, perfluoroalkanoic acids and salts having about 3 to about 24 carbon atoms per molecule (e.g., perfluorooctanoic acid, perfluoropropanoic acid, and perfluorononanoic acid), modified fatty alkylolamides, polyoxyethylene alkyl aryl ethers, octylphenoxyethanol, ethanolated alkyl guanidine-amine complexes, condensation of hydrogenated tallow amide and ethylene oxide, ethylene cyclomido 1-lauryl, 2-hydroxy, ethylene sodium alcoholate, methylene sodium carboxylate, alkyl arylsulfonates, sodium alkyl naphthalene sulfonate, sodium hydrocarbon sulfonates, petroleum sulfonates, sodium linear alkyl aryl sulfonates, alpha olefin sulfonates, condensation product of propylene oxide with ethylene oxide, sodium salt of sulfated fatty alcohols, octylphenoxy polyethoxy ethanol, sorbitan monolaurate, sorbitan monopalmitate, sorbitan trioleate, polyoxyethylene sorbitan tristearate, polyoxyethylene sorbitan tristearate, polyoxyethylene sorbitan monooleate, dioctyl sodium sulfosuccinate, modified phthalic glycerol alkyl resin, octylphenoxy polyethoxy ethanol, acetylphenoxy polyethoxy ethanol, dimethyl didodecenyl ammonium chloride, methyl trioctenyl ammonium iodide, sodium tridecyl ether sulfate, trimethyl decenyl ammonium chloride, and dibutyl dihexadecenyl ammonium chloride.

In one embodiment the gel composition comprises a surfactant made of alcohol ether sulfates (AES). Alcohol ether sulfates provide a good foaming performance in acid brines with a broad range of ionic strength and hardness. They allow the liquid phase of the foam to form a strong and robust gel under acid conditions.

The foaming gas is usually a noncondensable gas. Exemplary noncondensable gases include air, oxygen, hydrogen, noble gases (helium, neon, argon, krypton, xenon, and radon), natural gas, hydrocarbon gases (e.g., methane, ethane), nitrogen, and carbon dioxide.

The amount of gas injected (when measured at the temperature and pressure conditions in the subterranean formation being treated) is generally about 1 to about 99 volume percent based upon the total volume of treatment fluids injected into the subterranean formation (i.e., the sum of the volume of injected gas plus the volume of injected foamable, gel-forming composition). According to one embodiment, the amount of gas injected is about 20 to about 98, and more preferably about 40 to about 95, volume percent based upon the total volume of injected treatment fluids.

According to a first aspect, the gel composition with the gelling accelerator is especially suitable for downhole application in low temperatures below 300° F. (149° C.), or below 250° F. (121° C.), or below 225° F. (107° C.) or even below 200° F. (93° C.). The composition gelation will be primarily controlled by thermal release of the active crosslinker from crosslinking agents. This thermal reaction can be slow at lower temperatures, a gelling accelerator or gelation accelerator is suitable.

According to a second aspect, the gel composition with the gelling accelerator is especially suitable for downhole application in low temperatures below 300° F. (149° C.), or below 250° F. (121° C.), or below 225° F. (107° C.) or even below 200° F. (93° C.) when used in subterranean formation with carbonates formation. In prior art solutions, usually the gelation was accelerated by adding 0.1-0.4% by weight acid, e.g. acetic acid. However, when treating carbonate reservoirs, acid will be consumed by reaction with the rock and the composition gelation will be primarily controlled by thermal release of the active crosslinker from crosslinking agents. This thermal reaction can be slow at lower temperatures, and alternative accelerators as disclosed herewith are therefore needed for the gelation in carbonate reservoirs at relatively low temperatures.

The composition gels are compatible with other fluids or material as for example hydrocarbons such as mineral oil, proppants or additives normally found in well stimulation. Current embodiments can be used in various applications including temporary plugs formation, kill plugs, or multiple fracturing steps for to treating subterranean formations having a plurality of zones of differing permeabilities.

To facilitate a better understanding of some embodiments, the following examples of embodiments are given. In no way should the following examples be read to limit, or define, the scope of the embodiments described herewith.

EXAMPLES

Series of experiments were conducted to demonstrate properties of compositions and methods as disclosed above.

Example 1

In a first example, three fluids are shown in FIG. 1. Fluid 1 was prepared by hydrating 1.25% acrylamide sodium acrylate copolymer in water, followed by the addition of 0.2% hexamethylenetetramine and 0.1% phenyl acetate. Fluid 1 was used as the control sample. The viscosity at 212° F. (100° C.) was measured with a Fann50-type viscometer at 400 psi of nitrogen (N2). The fluid viscosity slowly went up over time, reaching 200 cP after about 500 minutes. Fluid 2 was similarly prepared as Fluid 1 with water, 1.25% acrylamide sodium acrylate copolymer, 0.2% hexamethylenetetramine, and 0.1% phenyl acetate. The difference was that the viscosity of Fluid 2 at 212° F. was measured with a Fann50-type viscometer at 400 psi of carbon dioxide (CO2). The viscosity of Fluid 2 quickly went up after about 100 minutes, reaching 1000 cP at about 300 minutes, suggesting that CO2 accelerated the fluid gelation at 212° F. Fluid 3 was similarly prepared as Fluid 1 with water, 1.25% acrylamide sodium acrylate copolymer, 0.2% hexamethylenetetramine, and 0.1% phenyl acetate. To simulate the carbonate formation, 2% CaCO3 powder (Fisher Chemical) was mixed into Fluid 3. The foaming agent solution at 0.5% was also added into Fluid 3. The viscosity of Fluid 3 at 212° F. was measured with a Fann50-type viscometer at 400 psi of CO2. The behavior of Fluid 3 was similar to that of Fluid 2, suggesting that carbonate or the foaming agent did not have negative impact on the gelation acceleration by CO2.

Example 2

In a second example, test was performed to see if mineral oil had negative impact on the gelation acceleration by CO2. To prepare Fluid 1, instead of acrylamide sodium acrylate copolymer, sodium acrylate acrylamide copolymer dispersed in mineral oil was used at 2%, along with 0.2% hexamethylenetetramine and 0.1% phenyl acetate. The viscosity of Fluid 1 at 212° F. (100° C.) was measured with a Fann50-type viscometer at 400 psi of CO2 and shown in FIG. 2. Fluid 1 behaved qualitatively the same as Fluid 2 in Example 1, suggesting that the mineral oil did not have negative impact on the gelation acceleration by CO2.

CO2 may be added to the fluids as the energizing gas, or may be generated by the decomposition of chemicals downhole, or may be generated by other chemical reactions downhole (e.g., acid reacts with carbonate formation).

Example 3

In a third example, Fluid 1 was prepared by hydrating 1.25% acrylamide sodium acrylate copolymer in water, followed by the addition of 0.2% hexamethylenetetramine and 0.1% phenyl acetate. Fluid 1 was used as the control sample. The viscosity at 225° F. (107° C.) was measured with a Fann50-type viscometer at 400 psi of nitrogen (N2) and shown in FIG. 3. Fluid 2 was similarly prepared as Fluid 1 with water, 1.25% acrylamide sodium acrylate copolymer, 0.2% hexamethylenetetramine, and 0.1% phenyl acetate. About 1.2% polylactide fibers were then mixed into Fluid 2. The viscosity at 225° F. was similarly measured at 400 psi of N2 and shown in FIG. 3. The viscosity of Fluid 2 rose at a much faster rate than that of Fluid 1 after about 400 minutes, suggesting that the polylactide fibers contributed to the gelation acceleration of the fluid at 225° F.

Example 4

Fluid 1 was prepared by hydrating 1.25% acrylamide sodium acrylate copolymer in water, followed by the addition of 0.2% hexamethylenetetramine and 0.1% phenyl acetate. Fluid 1 was used as the control fluid. The viscosity at 250° F. (121° C.) was measured with a Fann50-type viscometer at 400 psi of N2 and shown in FIG. 4. Fluid 2 was similarly prepared as Fluid 1 with water, 1.25% acrylamide sodium acrylate copolymer, 0.2% hexamethylenetetramine, and 0.1% phenyl acetate. About 0.6% polylactide fibers were then mixed into Fluid 2. The viscosity at 250° F. was similarly measured at 400 psi of N2 and shown in FIG. 2. The viscosity of Fluid 2 rose at a much faster rate than that of Fluid 1 after about 250 minutes, suggesting that the polylactide fibers contributed to the gelation acceleration of the fluid at 250° F.

Example 5

Fluid 1 was prepared with water, 1.25% acrylamide sodium acrylate copolymer, 0.2% hexamethylenetetramine, and 0.1% phenyl acetate. Fluid 2 was prepared with water, 1.25% acrylamide sodium acrylate copolymer, 0.2% hexamethylenetetramine, and 0.1% phenyl acetate. About 100 ppt polylactide fibers were then mixed into Fluid 2. To simulate the carbonate formation, 2% CaCO3 powder (Fisher Chemical) was also mixed into Fluid 2. The viscosity of Fluid 1 and Fluid 2 at 225° F. (107° C.) was similarly measured at 400 psi of N2 and shown in FIG. 5. The viscosity of Fluid 2 rose at a much faster rate than that of Fluid 1 (the control) after about 380 minutes, suggesting that the carbonate did not affect the ability of the polylactide fibers to accelerate the gelation at 225° F.

Example 6

In this example, we tested if mineral oil had negative impact on the gelation acceleration by polylactide fibers. To prepare Fluid 1, instead of acrylamide sodium acrylate copolymer, sodium acrylate acrylamide copolymer dispersed in mineral oil was used at 2%, along with 0.2% hexamethylenetetramine and 0.1% phenyl acetate. About 1.2% polylactide fibers were then mixed into Fluid 1. The viscosity of Fluid 1 at 225° F. (107° C.) was measured with a Fann50-type viscometer at 400 psi of N2 and shown in FIG. 6. Fluid 1 behaved qualitatively the same as Fluid 2 in Example 3 at 225° F., suggesting that the mineral oil did not have negative impact on the gelation acceleration by polylactide fibers.

Example 7

In this example, we tested if encapsulated acid works as gelling accelerator. Bottle tests were performed by adding 10 mL of a formulation to a crimp top chromatography vial sealed with a rubber stopper. These ampoules severely retard air intrusion into the gel and water vapor escape from the gel. Typical screw cap vials tend to dry out over time when held at elevated temperatures. The formulations include partially hydrolyzed polyacrylamide polymer dissolved in deionized water, hexamethylenetetramine, phenyl acetate, and either live or encapsulated acid. Acetic acid is used for live acid in these experiments while samples of encapsulated citric and fumaric acid were tested. The amount of acid was estimated from prior work and was decreased as the storage temperature increased. The ampoules' head space is briefly purged with argon to remove most of the reactive oxygen from the air before the ampoules are crimped. Ampoules are then placed into various ovens maintained at a constant temperature.

Periodically, the ampoules are removed from the oven, inverted and visually rated, and then returned to the oven. The letter grade is recorded according to the chart shown in the table 1 below.

TABLE 1 A No detectable gel formed: The gel appears to have the same viscosity (fluidity) as the original polymer solution and no gel is visually detectable. B Highly flowing gel: The gel appears to be only slightly more viscous (less fluid) than the original polymer solution. C Flowing gel: Most of the obviously detectable gel flows to the bottle cap upon inversion. D Moderately flowing gel: Only a small portion (about 5 to 15%) of the gel does not readily flow to the bottle cap upon inversion-- usually characterized as a “tonguing” gel (i.e., after hanging out of jar, gel can be made to flow back into bottle by slowly turning bottle upright). E Barely flowing gel: The gel can barely flow to the bottle cap and/or significant portion (>15%) of the gel does not flow upon inversion. F Highly deformable nonflowing gel: The gel does not flow to the bottle cap upon inversion. G Moderately deformable nonflowing gel: The gel flows about half way down the bottle upon inversion. H Slightly deformable nonflowing gel: The gel surface only slightly deforms upon inversion. I Rigid gel: There is no gel-surface deformation upon inversion. J Ringing rigid gel: A tuning-fork-like mechanical vibration can be felt after tapping the bottle. % X Syneresis: The amount of separated liquid is shown as a percentage of the original volume of fluid. This suggests instability and is to be avoided. Minor amounts of 10% or less pose no problems.

Four temperatures were used in these initial experiments and include ambient (70° F.), 150, 175 and 200° F. Three ampoules were prepared at each temperature. The first used acetic acid, the second encapsulated fumaric acid and the third was encapsulated citric acid. Note that acetic acid is monoprotic, fumaric acid is diprotic and citric acid is triprotic. The encapsulating layer was a lipid that softens and melts at elevated temperature. The fumaric acid was 75% active while the citric acid was 72% active

Table 2 below shows the concentrations tested. Clearly the gelation results are quite comparable for the different acids and concentrations used. The ambient formulations take several days and normally would require hydrochloric acid to achieve gelation in less than eight hours. Despite the increased temperature, the 200° F. gels were slower to achieve the same state of gelation because the acid content was lower. Using slightly more acid would have achieved a faster gelation.

TABLE 2 wt % wt % wt % acetic fumaric citric T Gel rating at indicated hours No. acid acid acid (° F.) 1 2 3 4 5 6 7 22 46 122 1 0.8 70 A A A A A A A A A A 2 1.1 70 A A A A A A A A A A 3 1.2 70 A A A A A A A A A A 4 0.8 150 A A A A A A A I J J 5 1.1 150 A A A A A A A I J J 6 1.2 150 A A A A A A A J J J 7 0.3 175 A A H I I I I I I I 8 0.42 175 A A H I I I I I I I 9 0.44 175 A A G I I I I I I I 10 0.08 200 A A C E H I I H I I 11 0.11 200 A A D H I I I H I I 12 0.12 200 A A D E H I I H I I

The particular embodiments disclosed above are illustrative only, as the invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details herein shown, other than as described in the claims below. It is therefore evident that the particular embodiments disclosed above may be altered or modified and all such variations are considered within the scope of the embodiments described herewith. Accordingly, the protection sought herein is as set forth in the claims below.

Claims

1. A method comprising:

a. injecting into a wellbore, a composition comprising a solvent, a crosslinkable polymer, a crosslinking agent capable of crosslinking the polymer or forming a polymer, and a gelling accelerator selected from the group consisting of carbon dioxide, polylactic acid, encapsulated acid and latent acid;
b. allowing viscosity of the composition to increase and form a gel more quickly with the gelling accelerator than without.

2. The method of claim 1, wherein the composition further comprises a foaming agent and a surfactant.

3. The method of claim 2, wherein the foaming agent is the gelling accelerator.

4. The method of claim 3, wherein the gelling accelerator is carbon dioxide.

5. The method of claim 1, wherein the encapsulated acid or latent acid is sodium metabisulfite.

6. The method of claim 1, wherein the solvent is water or brine.

7. The method of claim 1, wherein the crosslinkable polymer comprises acrylamide polymer and copolymer.

8. A method of treating a subterranean formation at least partially made of carbonate rock comprising:

a. injecting into a wellbore, a composition comprising a solvent, a crosslinkable polymer, a crosslinking agent capable of crosslinking the polymer or forming a polymer, and a gelling accelerator, wherein the gelling accelerator is substantially inert to the carbonate rock;
b. contacting the composition with the subterranean formation, wherein the temperature is below 150 degrees Celsius at this contact;
c. allowing viscosity of the composition to increase and form a gel more quickly with the gelling accelerator than without.

9. The method of claim 8, wherein the composition further comprises a foaming agent and a surfactant.

10. The method of claim 9, wherein the foaming agent is the gelling accelerator.

11. The method of claim 10, wherein the gelling accelerator is carbon dioxide.

12. The method of claim 8, wherein the gelling accelerator is carbon dioxide.

13. The method of claim 8, wherein the gelling accelerator is polylactic acid fiber.

14. The method of claim 8, wherein the gelling accelerator is a delayed acid release component.

15. The method of claim 14, wherein the gelling accelerator is encapsulated acid or latent acid.

16. The method of claim 15, wherein the encapsulated acid or latent acid is sodium metabisulfite.

17. The method of claim 8, wherein the solvent is water or brine.

18. The method of claim 8, wherein the crosslinkable polymer comprises acrylamide polymer and copolymer.

19. The method of claim 8, wherein the temperature is below 130 degrees Celsius.

20. The method of claim 8, wherein the temperature is below 110 degrees Celsius.

21. The method of claim 8, wherein the temperature is below 95 degrees Celsius.

22. A method of treating a subterranean formation made at least partially of carbonate rock comprising:

a. injecting into a wellbore, a composition comprising a solvent, a crosslinkable polymer, a crosslinking agent capable of crosslinking the polymer or forming a polymer, a surfactant and carbon dioxide;
b. contacting the composition with the subterranean formation, wherein the temperature is below 130 degrees Celsius at this contact;
c. allowing viscosity of the composition to increase and form a gel more quickly with the carbon dioxide than without.

23. The method of claim 22, wherein the solvent is water or brine.

24. The method of claim 22, wherein the crosslinkable polymer comprises acrylamide polymer and copolymer.

25. The method of claim 22, wherein the temperature is below 110 degrees Celsius.

Patent History
Publication number: 20110315383
Type: Application
Filed: Jun 23, 2010
Publication Date: Dec 29, 2011
Inventors: Leiming Li (Sugar Land, TX), Lijun Lin (Sugar Land, TX), Syed A. Ali (Sugar Land, TX), Curtis L. Boney (Houston, TX), Richard D. Hutchins (Sugar Land, TX)
Application Number: 12/821,881
Classifications
Current U.S. Class: Chemical Inter-reaction Of Two Or More Introduced Materials (e.g., Selective Plugging Or Surfactant) (166/300)
International Classification: E21B 43/22 (20060101);