BRPI0618879A2 - Method for stabilizing portions of an underground formation comprising unconsolidated particulates - Google Patents

Abstract

Method for stabilizing portions of an underground formation comprising unconsolidated particulates Methods for stabilizing portions of an underground formation comprising unconsolidated particulates. In one embodiment, the methods of the present invention comprise: providing a consolidating agent; introducing the consolidating agent into an unconsolidated portion of an underground formation through a dynamic offset tool; and allowing the consolidating agent to at least partially consolidate the unconsolidated portion of the underground formation.

Description

"Method for stabilizing portions of an underground formation comprising unconsolidated sides"

GROUNDS

The present invention relates to the treatment of formations

underground. More particularly, the present invention relates to methods for stabilizing portions of an underground formation comprising unconsolidated particulates.

Hydrocarbon wells are often located in underground formations that contain unconsolidated particulates (eg, sand, gravel, support, fines, etc.) that may migrate outwards.

underground formation in a wellbore and / or may be produced with oil, gas, water and / or other fluids produced by the well. The presence of such particulates in the fluids produced is undesirable where the particulates may accommodate pumping and other equipment production and / or reduce the desired well fluid production. In addition, particulates that have migrated into a wellbore (for example, inside casings and / or drilled holes in a wellbore), among other things, can clog the wellbore portions, preventing the production of desired wellbore fluids. . φ 20 The term "unconsolidated particles," and derivatives thereof, is defined herein to include loose particles and bound particles with insufficient binding power to withstand the forces created by the production of fluids through formation. Unbound particulates may comprise, among other things, sand, gravel, fines and / or supporting particulates in the underground formation, for example, supporting particulates placed in the underground formation in the course of a fracture or gravel filling operation. The terms "unconsolidated underground formations," "unconsolidated portions of an underground formation" and derivatives thereof are defined herein to include any formations containing unconsolidated particulates as defined herein. The "unconsolidated underground formations" and "unconsolidated portions of an underground formation," as these terms are used here, include underground fractures where unconsolidated particulates reside within the open space of the fracture (for example, forming a filling bearing within the fracture).

One method of controlling unconsolidated particulates in underground formations involves placing a gravel containing filtration bed (for example, a "gravel filler") near the wellbore to provide a physical barrier to transporting unconsolidated particulates with desired fluid production. Typically, such "gravel filling operations" involve pumping and placing a quantity of certain particulate into the unconsolidated underground formation in an area adjacent to a wellbore. A common type of gravel filling operation involves placing a screen in the pit hole and filling the surrounding ring between the screen and the gravel pit hole of a specific size designed to prevent the passage of sand formation. The screen is usually a filter assembly used to hold gravel placed during the gravel filling operation. A wide range of screen sizes and configurations is available to adjust the characteristics of the gravel filler sand used. Similarly, a wide range of gravel sizes is available to adjust the characteristics of unconsolidated particulates in the underground formation. To install the gravel filling, the gravel is formed into a paste by mixing the gravel with a fluid, which is usually viscous. Once the gravel is placed in the wellbore, the viscosity of the treatment fluid can be reduced and is returned to the surface. The resulting structure presents a barrier to migrate sand from the formation while still allowing fluid flow. φ €

Meantime? The use of such gravel filling methods can be problematic. For example, gravel fillings can be time consuming and expensive to install. Due to the time and expense required, it is sometimes desirable to place a screen without gravel. Even in circumstances where it is practical to lay a screen without gravel, it is often difficult to determine an appropriate screen size to use as a sandy formation that tends to have a wide distribution of grain sizes. When small amounts of sand are allowed to flow through a screen, erosion formation becomes a significant concern. As a result, gravel as well as screen placement is often required to ensure that sand formation is controlled. Expandable sand screens have been developed and implemented in recent years. As part of the installation, an expandable sand screen may be expanded against the pit hole, coated hole or open hole for sand control purposes without the need for gravel filling. However, expandable screens can still have problems such as screen erosion and screen buffering.

Another method used to control unconsolidated particulates in underground formations involves consolidating unconsolidated particles into stable masses permeable by applying a consolidating agent (e.g. a resin or tackifier) to the underground formation. However, it may be desirable in some cases, preferably, to place a consolidating agent in a particular region of an underground formation (e.g., an unconsolidated portion) penetrated by a wellbore. To place the consolidating agent in a specific region of an underground formation, certain types of insulation tools, such as "filling" devices, packers, gel plugs, mechanical plugs, bridge plugs, spherical sealants, and others, were used in the technique to isolate certain φ ί

intervals of an underground formation and place a consolidating agent in a region of the underground formation within that interval. However, the use of these isolation tools can be problematic. First, in applications where it is desirable to treat multiple regions of an underground formation 5 at multiple different intervals, the insulation tools used must be removed and repositioned to subsequently isolate treated intervals, a process which may, among other things, cause damage to the formation. and / or the borehole, and increase the cost, complexity, and duration of operation.In addition, in methods using these isolation tools, a certain amount of consolidating agent and / or associated treatment fluid (s) ( s) introduced into the underground formation usually "leaks" into the underground formation regions outside the isolated range, and thus those methods which generally require larger amounts of consolidating agent (and / or the treatment fluid that carries the forming agent). consolidation) ensure that the isolated interval of underground formation is completely treated.

SUMMARY

The present invention relates to the treatment of underground formations. More particularly, the present invention relates to methods for stabilizing portions of an underground formation comprising unconsolidated particulates.

In one embodiment, the present invention provides a method comprising: providing a consolidating agent; introducing the consolidating agent into an unconsolidated portion of an underground formation through a dynamic offset tool; and allowing the consolidating agent to at least partially consolidate the unconsolidated portion of the underground formation.

In another embodiment, the present invention provides a method comprising: providing a consolidating agent; 4b introducing the consolidating agent into an unconsolidated portion of an underground formation via a dynamic offset tool, wherein a plurality of unconsolidated holding particles reside within the underground formation; and allowing the consolidating agent to at least partially consolidate the unconsolidated supporting particles within the unconsolidated portion of the underground formation.

%

In another embodiment, the present invention provides a method comprising: providing a consolidating agent; introducing the consolidating agent into an unconsolidated portion of an underground formation via a dynamic offset tool, wherein a plurality of unconsolidated formation particles reside within the underground formation; and allowing the consolidating agent to at least partially consolidate the unconsolidated formation particles into the underground formation. Aspects and advantages of the present invention will be

apparent to those skilled in the art. While numerous changes can be made by those skilled in the art, such changes are within the spirit of the invention.

BRIEF DESCRIPTION OF THE DRAWINGS These drawings illustrate certain aspects of some of the shapes

of the present invention and should not be used to limit or define the invention.

FIGURE 1 illustrates a side view of an underground formation that may be treated in certain embodiments of the present invention.

FIGURE 2 illustrates a side view of an underground formation to be treated during the course of an embodiment of the present invention.

FIGURE 3 illustrates a side view of an underground formation to be treated during the course of an embodiment of the present invention.

FIGURE 4 illustrates a side view of an underground formation to be treated during the course of an embodiment of the present invention.

FIGURE 5 illustrates a side view of an underground formation to be treated during the course of an embodiment of the present invention.

FIGURE 6 illustrates a side view of an underground formation to be treated during the course of an embodiment of the present invention.

FIGURE 7 illustrates a side view of an underground formation that has been treated in the course of an embodiment of the present invention.

DESCRIPTION OF PREFERRED EMBODIMENTS

The present invention relates to the treatment of underground formations. More particularly, the present invention relates to methods for stabilizing portions of an underground formation comprising unconsolidated particulates. I. METHODS OF THE INVENTION

The methods of the present invention generally comprise: providing a consolidating agent; introducing the consolidating agent into an unconsolidated portion of an underground formation through a dynamic offset tool; and allowing the consolidating agent to at least partially consolidate the unconsolidated portion of the underground formation. The consolidating agent may be supplied and / or introduced into the underground formation as a component of one or more treatment fluids introduced into the underground formation. The term "consolidating agent" is defined herein to include any substance that can stabilize a portion of the underground formation that can at least in part stabilize unconsolidated particulates such that they are prevented from displacement or migration. The term "dynamic offset tool" is defined herein to include any device that is capable of modifying (e.g. increasing) the velocity of a fluid in an underground formation from the velocity of that fluid in a wellbore. The methods of the present invention may be used to at least partially consolidate a selected range into an unconsolidated portion of an underground formation without the need for insulation tools.

used before in the technique.

The underground formations treated in the methods of the present invention may be any underground formations wherein at least a plurality of unconsolidated particles reside in the formation. An example of such an underground formation is illustrated in FIGURE 1. A well bore 110 penetrates at some different intervals from the underground formation represented therein; some of the ranges comprise the consolidated portions 121, 122, 123, 124, and 125, while some ranges comprise the unconsolidated portions 131, 132, 133, and 134, which comprise at least a plurality of unconsolidated particulates. These unconsolidated particulates may comprise, among other things, sand, gravel, fm and / or supporting particulates within the open space of one or more underground formation fractures (for example, unconsolidated supporting particulates that form a supporting filling within fracture). Supporting particulates may be comprised of any material suitable for use in underground operations. Examples include, but are not limited to, sand, bauxite, ceramic materials, glass materials (eg glass beads), polymeric materials, Teflon® materials, nutshell pieces, seed shell pieces, particulates. cured resinous materials comprising pieces of

¥ 4

<walnut shell, cured resinous particulates comprising seed husk pieces, fruit stone pieces, cured resinous particles comprising fruit stone pieces, wood, composite particulates and combinations of these composite particles may also be used wherein the suitable composite materials may comprise a binder material and a filler wherein suitable filler materials include silica, alumina, fumigated carbon, carbon black, graphite, mica, titanium dioxide, meta silicate, calcium silicate, kaolin, talc, zirconia, boron, fly ash, concave glass microspheres, solid glass, ground walnut / seed husks or shells, sawdust, ground cellulose fiber and combinations thereof. Typically, the particulates have a size in the range from about 2 to about 400 mesh, in the US Sieve Series. In particular embodiments, particle size distribution variations are one or more than 6/12 mesh. 16, 12/20, 16/30, 20/40, 30/50, 40/60, 40/70, or 50/70 mesh. It is to be understood that the term "particulate," as used in this disclosure, includes all known forms of materials that include substantially spherical materials, fibrous materials, polygonal materials (such as cubic materials) and mixtures thereof. In addition, fibrous materials that can be used, inter alia, to withstand the pressure of a closed fracture, are often included. In some embodiments, the carrier particles may be coated with any suitable resin or tackifier known to those of ordinary skill in the art.

Underground formations treated in the methods of the present invention may be penetrated by a wellbore through which the consolidating agent and / or other treatment fluids may be introduced, for example, as shown by wellbore 110 in FIGURE 1. A Well borehole that penetrates the underground formation to be treated may contain one or more casing pipes or columns (for example, a wellbore

ÍS

"coated" or "partially coated"), as shown by coating 140 in wellbore 110 in FIGURE 1. In certain embodiments, the wellbore may be decoated. In certain embodiments, a wellbore that penetrates the underground formation may contain one or more grades and / or gravel fillings, among other purposes, to reduce the migration of sandy formation in the wellbore. In other embodiments, the wellbore may not contain any such screens or gravel fillings (for example, an "unprotected" wellbore).

In those embodiments where the wellbore portion that penetrates the portion of the underground formation to be treated is coated or partially coated, the dynamic diverter tool may introduce fluids and / or the consolidating agent into the underground formation by directing through boreholes. or holes in the liner that allow fluid communication between the liner interior and the ring (i.e. the space between the wellbore walls and the outer liner surface). Referring now to FIGURE 1, one or more perforations 150 may be created in casing 140 which is fitted in well bore 110 to allow fluid communication between the casing interior and an unconsolidated portion 134 of the underground formation. In certain embodiments, the dynamic offset tool may be used to create such perforations or holes in the coating, for example by driving a fluid comprising abrasive materials (e.g., particulate materials such as sand, gravel, particulates degradable and others) on the interior surface of the coating and / or propel a fluid at a sufficiently high pressure on the interior surface of the coating to create perforations or holes in the coating. In other embodiments, the perforations or holes may be created using some other method or apparatus before or during the driving course of a method of the present invention. In certain embodiments, the particles residing in the perforations or holes in the coating may be replaced by the consolidating agent (or the fluid comprising the consolidating agent), which may, inter alia, enhance or restore fluid flow therethrough. perforations or holes in the coating.

Referring now to FIGURE 2, the offset tool

The dynamic bias 210 may be placed in the wellbore with a pipe column comprising coiled tubing or hinged tube 220. The dynamic bias tool 210 is placed in a portion of the wellbore adjacent an unconsolidated portion 134 of the underground formation. Referring now to FIGURE 3, the consolidating agent may be introduced through the coiled tubing or hinged tube 220 to the dynamic offset tool 210, where the tool may direct the consolidating agent 320 into the unconsolidated portion 134 of the underground formation.

In certain embodiments, it may not be desirable to use certain types of dynamic deflection tools that are capable of propelling fluid at a pressure sufficient to corrode and / or fracture a portion of the underground formation. However, in certain embodiments, it may be desirable to use certain types of dynamic diverter tools that are capable of propelling fluid at a pressure sufficient to penetrate through a gravel filler and / or screen that resides in the wellbore. One of ordinary skill in the art, for the benefit of this disclosure, will recognize when certain types of dynamic offset tools are suitable or inappropriate for a particular application of the methods of the present invention, depending on a variety of factors, including rate and / or desired fluid flow pressure, the structure and / or composition of the underground formation, the length of the gap in the underground formation to be treated, and the like. Examples of dynamic offset tools that may be suitable for the methods of the present invention are described in Section II below.

The methods of the present invention may optionally include providing and introducing one or more pre-wash fluids into the underground formation at any point prior to, during, or subsequent to performing the methods of the present invention. Typically, injection of a prewash fluid may occur at any time before the consolidating agent is introduced into the underground formation. In certain embodiments, a prewash fluid may be applied to the underground formation, among other purposes, to clean undesirable substances (e.g., oil, residue or debris) from the pore spaces in the underground formation matrix to clean such undesirable substances residing in the perforations or holes in a casing column and / or to prepare the underground formation for subsequent placement of the consolidating agent. For example, an acidic prewash fluid may be introduced into at least a portion of the underground formation which may, inter alia, dissolve undesirable substances in the underground formation. Prewash fluid can be introduced into the underground formation through the dynamic bypass tool, directly pumped into the annular space between the walls of a well bore and a casing column that penetrates the underground formation or, introduced into the underground formation by any other suitable means. Generally, the volume of prewash fluid introduced into the formation is between 0.1 times to 50 times the volume of the consolidating agent. Examples of prewash fluids suitable for use with the present invention are described in more detail in Section III.A. below, down, beneath, underneath, downwards, downhill.

The methods of the present invention optionally may be

comprise placing a static biasing agent within a portion of the underground formation. As used herein, the term "static bypass agent" is defined to include any static bypass agent or tool (for example, chemicals, fluids, particulates or

(Equipment) which is capable of diverting fluid flow away from a particular portion of an underground formation to another portion of the underground formation. Among other things, the static offset agent can assist in controlling the placement of the consolidation agent in the desired area. Examples of suitable static shifting agents include, but are not limited to, fluids (e.g., aqueous based and / or non-aqueous based fluids), emulsions, gels, foams, degradable materials (e.g. polyesters, orthoesters). , poly (orthoesters), polyanhydrides, dehydrated organic and / or inorganic compounds), particulates, packing (eg precision packing and selective injection packing), spherical sealants, pack-off devices, particulates, sand plugs, bridge and others. One skilled in the art, for the benefit of this disclosure, will recognize when a static bypass agent should be used in a method of the present invention, as well as the appropriate type of static bypass agent placement.

The methods of the present invention may be used to consolidate a single interval into an unconsolidated portion of an underground formation or may be repeated to consolidate a few different intervals into an underground formation. Referring now to FIGURE 3, for example, the dynamic offset tool 210 may initially be positioned within a well bore so that it enters the consolidating agent 320 at a particular interval 134 into a portion of an underground formation. . As shown in FIGURE 4, after introducing the consolidating agent 320 into this particular range 134, the dynamic offset tool 210 can be repositioned so that it introduces the consolidating agent 420 into another gap 133 in the underground formation (e.g. closer to the surface than the first treated interval). As shown in FIGURE 5, this process may be repeated for any number of other intervals comprising untreated portions.

$ 1

132 and 131 of an underground formation, introduce the consolidating agent 520 into those portions of the underground formation. In embodiments where several different gaps are treated, the various gaps may be penetrated by a single well bore, different contiguous well bores 5, or different non-contiguous well bore. After treatment of one or more intervals, the dynamic offset tool 210 may then be relocated to the bottom of the wellbore Il5 as shown in FIGURE 5.

The methods of the present invention optionally may include providing and applying one or more post-wash fluids to the underground formation at any stage of the treatment process.

Typically, injection of a postwash fluid may occur at any time after the consolidating agent is introduced into the underground formation. When used, the afterwash fluid is preferably placed in the underground formation while the consolidating agent is still in a state of flux. For example, an afterwash fluid may be placed in the formation prior to a closed period. In certain embodiments, a postwash fluid may be applied to the underground formation, among other purposes, to activate the consolidating agent φ 20 and / or to restore the permeability of a portion of the underground formation by replacing at least a portion of the pore channel consolidating agent therein or forcing the substituted portion of the consolidating agent further into underground formation where it may have negligible impact on subsequent hydrocarbon production. The afterwash fluid may be introduced into the underground formation through the dynamic bypass tool directly pumped into the annular space between the walls of a wellbore and a casing column that penetrates the underground formation or, introduced into the underground formation by any other suitable means. As shown in FIGURE 6, the dynamic offset tool 210 may be repositioned in well borehole IlOe used to circulate an afterwash fluid 660 in the wellbore to restore fluid circulation in the wellbore portion 611 and 612 adjacent an underground formation region 133 and 134 which has been consolidated in the methods of the present invention. As shown in FIGURE 7, this process can be repeated for each interval until fluid circulation is restored to the full length of wellbore 711, and the dynamic offset tool can then be removed from the wellbore. Generally, the volume of post-wash fluid introduced into the underground formation ranges from about 0.1 times to about 50 times the volume of the consolidating agent. In some embodiments of the present invention, the volume of post-wash fluid introduced into the underground formation ranges from about 0.1 times to about 5 times the volume of the consolidating agent. Examples of afterwashing fluid suitable for use with the present invention are described in more detail in Section III.A. below, down, beneath, underneath, downwards, downhill.

The methods of the present invention may be used before, in combination with, or after any type of underground operation to be performed in underground formation, including, but not limited to fracture operations, gravel filling operations, fracture operations. - stuffing (ie combination of fracture and gravel stuffing operations), and others. For example, the methods of the present invention may be used at the same time after a fracture operation, wherein the methods of the present invention are used, at least partially, to consolidate the holding particles placed within one or more created fractures. or intensified during the fracture operation. In certain embodiments, the methods of the present invention may optionally comprise introducing other additives and treatment fluids, such as relative permeability modifiers, support, surfactants, gases, biocides, acids, or any other additives or fluids. treatment, in the underground formation through the dynamic shifting tool and / or by any other suitable means to introduce such additives or treatment fluids into the underground formation.

II. Dynamic Offset Tools * 5 The methods of the present invention utilize a tool for

dynamic shift to introduce treatment fluids into the formation

«

underground. Dynamic biasing tools suitable for use in the present invention may comprise any assembly that is capable of modifying (e.g., increasing) the velocity of a fluid in an underground formation from the velocity of that fluid in a wellbore. In certain embodiments, the dynamic offset tool may comprise a column of tubes (e.g. spiral pipe, drill pipe, etc.) with at least one hole (e.g. nozzle or outlet pipe) in it which is able to direct fluid flow within the pipe column in an underground formation in a desired direction. Examples of suitable dynamic offset tools include, but are not limited to, subassemblies provided with holes, hydrodetontion tools, and hydroblasting tools, which include those described in the following US patents and patent applications, the relevant disclosures of which are incorporated herein by reference: US Patent Serial Number 5,765,642; U.S. Patent Serial Number 5,249,628; U.S. Patent Serial Number 5,325,923; U.S. Patent Serial Number 5,499,678; U.S. Patent Serial Number 5,396,957; U.S. Patent Application Serial Number 11 / 004,441 by East, Jr. et al. In certain embodiments, the dynamic offset tool may comprise an acoustic tool or a pulsed tool (for example, a tool capable of applying a pressure pulse having a given amplitude and frequency to a fluid). Examples of suitable acoustic and pulse tools include, but are not limited to, fluidic oscillators and those devices described in Patent Application.

ι «3

Serial No. 10 / 83,706 by Nguyen, et al., The relevant disclosure of which is incorporated herein by reference. In embodiments where the dynamic offset tool comprises a pulsed tool, the acoustic energy generated by the pulsed tool may, inter alia, further stabilize the unconsolidated particulates in the underground formation in conjunction with the consolidating agent used. In certain embodiments, the dynamic offset tool may comprise a cementless liner having outlet tubes on the outer surface of the liner.

Selecting a suitable dynamic offset tool

for a particular application of the present invention may depend on a variety of factors, including the rate and / or pressure of the desired fluid flow, the structure and / or composition of the underground formation, the length of the underground formation gap to be treated, the particular composition of the fluid to be introduced into the underground formation, and others. For example, in certain embodiments, it may or may not be desirable to use certain types of dynamic offset tools that are capable of propelling fluid at a pressure sufficient to corrode and / or fracture a portion of the underground formation. One of ordinary skill in the art, with the benefit of this disclosure, will be able to recognize which types of dynamic offset tools are suitable for a particular application of the methods of the present invention.

III Fluids

In certain embodiments, the consolidating agent may be supplied and / or introduced into the underground formation as a component of one or more treatment fluids introduced into the underground formation. Such treatment fluids may include any fluid that does not adversely interact with the other components used in accordance with this invention or underground formation. Such treatment fluids may be aqueous based or non-aqueous based. The aqueous based treatment fluids may comprise freshwater, saltwater, brine, seawater or a combination thereof. Non-aqueous based treatment fluids may comprise one or more organic liquids such as hydrocarbons (e.g. kerosene, xylene, toluene or diesel), oils (e.g. mineral oils or synthetic oils), esters and others.

Prewash and postwash fluids used in certain embodiments of the present invention may include any fluid that does not adversely interact with the other components used in accordance with this invention or with underground formation. For example, the prewash and postwash fluid may be an aqueous based fluid, a hydrocarbon based fluid (e.g. kerosene, xylene, toluene, diesel, oils, etc.), or a gas (e.g. nitrogen or carbon dioxide). Water-based fluids may comprise freshwater, saltwater, brine or seawater or any other aqueous fluid that does not adversely react with the other components used in accordance with this invention or underground formation. In certain embodiments, an aqueous based prewash and postwash fluid may comprise a surfactant. Any surfactant compatible with subsequent treatments (e.g., the consolidating agent) may be used in the present invention, for example, to assist a consolidating agent in flow to the contact points between adjacent particulates in the formation. Such surfactants include, but are not limited to, ethoxylated nonyl phenol phosphate esters, mixtures of one or more cationic surfactants, one or more nonionic surfactants and an alkyl phosphonate surfactant. Suitable mixtures of one or more cationic and nonionic surfactants are described in U.S. Patent No. 6,311,773, the relevant disclosure of which is incorporated herein by reference. A C1 -C22 alkyl phosphonate surfactant is preferred. The surfactant or surfactants used may be included in the fluid.

pre-wash and post-wash in an amount sufficient to prepare the underground formation to receive a consolidation agent treatment. In some embodiments of the present invention, the surfactant is present in the prewash and postwash fluid in an amount ranging from about 0.1% to about 3% by weight of the aqueous fluid.

Treatment fluids, prewash fluids and / or afterwash fluids used in the methods of the present invention may comprise any number of additional additives, including, but not limited to, salts, surfactants, acids, fluid loss control, gas, sparkling, corrosion inhibitors, scale inhibitors, catalysts, clay control agents, biocides, friction reducers, defoamers, locking agents, dispersants, flocculants, H2S decontaminants, CO2 decontaminants , oxygen decontaminants, lubricants, viscosifiers, breakers, weighting agents, relative permeability modifiers, particulate materials (e.g., supporting particulates) and others. In certain embodiments, treatment fluids, prewash fluids and / or post wash fluids may comprise an activator or catalyst which may be used inter alia to activate polymerization of the consolidating agent. One skilled in the art, for the benefit of this disclosure, will recognize the types of additives that may be included in treatment fluids, prewash fluids and / or post wash fluids for a particular application.

IV. Consolidation Agents

Suitable consolidating agents for the methods of the present invention include any composition that can stabilize a portion of the underground formation, which may at least in part stabilize the unconsolidated particulates such that they are prevented from change or migration. Examples of suitable consolidating agents include% 19 C

resins, tackifiers and gel-forming liquid compositions.

A. Resins

Resins suitable for use as the consolidating agents in the methods of the present invention include any suitable resin which is capable of forming a hardened, consolidated mass. The term "resin" as used herein includes any of numerous similar physically polymerized synthetic resins or chemically modified natural resins, which include, but are not limited to, thermoplastic materials and thermoset materials. Many of such resins are commonly used in underground consolidation operations and some suitable resins include two epoxy component based resins, novolac resins, polyepoxide resins, phenol-aldehyde resins, urea-aldehyde resins, urethane resins, resins. phenolic, furan resins, furan / furfuryl alcohol resins, phenolic / latex resins, phenol formaldehyde resins, polyester and hybrid resins and copolymers thereof, polyurethane and hybrid resins and copolymers thereof, acrylate resins and mixtures thereof . Some suitable resins, such as epoxy resins, can be cured with an internal catalyst or activator so that when pumped down, they can be cured using time and temperature only. Other suitable resins, such as furan resins, may be formulated to cure at a slow rate or require a time-delay catalyst or an external catalyst to help activate resin polymerization if the cure temperature is low (ie. less than 250 ° F (121 ° C)), but will cure under the effect of time and temperature if the forming temperature is above about 25 ° F (1210 ° C), preferably above about 300 ° F (149 ° C). ). Such external catalysts may be introduced into the underground formation through the dynamic shunt tool (e.g. as a component of a treatment fluid) and / or by some other means (e.g. pumped into the ring from the surface). It is within the ability of a person skilled in the art, for the benefit of this disclosure, to select a resin suitable for use in the embodiments of the present invention and to determine whether a catalyst is required to activate curing.

Selection of a suitable resin may be affected by the temperature of the underground formation at which the fluid will be introduced. By way of example, for underground formations having a static downhole temperature ("BHST") ranging from about 60 ° F (16 ° C) to about 250 ° F (121 ° C), two resins epoxy-based component comprising a hardenable resin component and a

curing agent component containing specific curing agents may be preferred. For underground formations having a BHST ranging from about 300 ° F (149 ° C) to about 600 ° F (316 ° C), a furan-based resin may be preferred. For underground formations having a BHST ranging from about 200 ° F (93 ° C) to about 400 ° F (204 ° C), a phenolic based resin or an epoxy HT component based resin may be used. appropriate. For underground formations having a BHST of at least about 175 ° F φ 20 (79 ° C), a phenol / phenol formaldehyde / furfuryl alcohol resin may also be suitable.

Any solvent that is compatible with the chosen resin and achieves the desired viscosity effect is suitable for use in the present invention. Some preferred solvents are those that have high flash points (e.g., about 125 ° F (52 ° C)) because of, among other things, environmental and safety concerns; such solvents include butyl lactate, butyl glycidyl ether, dipropylene glycol methyl ether, dipropylene glycol dimethyl ether, dimethyl formamide, diethylene glycol methyl ether, ethylene glycol butyl ether, diethylene glycol butyl ether, propylene carbonate, methanol, alcohol butyl, d-limonene, fatty acid methyl esters and combinations thereof. Other preferred solvents include aqueous dissolvable solvents such as methanol, isopropanol, butanol, glycol ether solvents and combinations thereof. Suitable glycolic ether solvents include, but are not limited to, diethylene glycol methyl ether, dipropylene glycol methyl ether, 2-butoxy ethanol, ethers of a C2 to C6 dihydric alkanol containing at least one C1 to C6 alkyl group, monoethers of dihydric alkanols, methoxypropanol, butoxyethanol, hexoxyethanol and isomers thereof. Selection of an appropriate solvent is dependent upon the resin chosen and is within the ability of a person skilled in the art with the benefit of this disclosure.

B. Stickiness Agents

The tackifiers suitable for use in the methods of the present invention are sticky and thus impart a degree of consolidation to the unconsolidated particulates in the underground formation. The term "sticky agent" is defined herein to include any composition that has a nature such that it is (or can be activated to become) somewhat sticky to the touch. In certain embodiments, the tackifier may be formulated such that it is "activated" at a slow rate by contact with a catalyst or activator or under certain conditions (e.g., temperature). Examples of suitable tackifiers which are suitable for use in the present invention include non-aqueous tackifiers, aqueous tackifiers and silyl modified polyamides.

One type of tackifier suitable for use in the present invention is a non-aqueous tackifier. An example of a suitable tackifier may comprise polyamides which are liquid or in solution at the temperature of the underground formation, such that they are by themselves non-hardening when introduced into the underground formation. An example of such a tackifier comprises a condensation reaction product comprised of commercially available polyacids and a polyamine. Suitable commercial products include compounds such as mixtures of C36 dibasic acids which contain some higher trimers and oligomers as well as small amounts of monomeric acids which are reacted with polyamines. Other polyacids include trimeric acids, synthetic acids produced from fatty acids, maleic anhydride, acrylic acid and others. Such acidic compounds are commercially available from companies such as Witco Corporation, Union Camp, Chemtall and Emery Industries. Reaction products are available, for example, from Champion Technologies, Inc. and Witco Corporation. Additional compounds that may be used as non-aqueous tackifiers include liquids and solutions of, for example, polyesters, polycarbonates and polycarbamates, natural resins such as shellac and others. Other suitable non-aqueous tackifiers are described in U.S. Patent Numbers 5.53.48 and 5.33.00, the relevant disclosures of which are incorporated herein by reference.

Non-aqueous tackifiers suitable for use in the present invention may be used such that they form non-hardening coatings or may be combined with a multifunctional material capable of reacting with the non-aqueous tackifier to form a hardened coating. A "hardened coating," as used herein, means that the reaction of the tackifier with the multifunctional material will result in a substantially non-flowing reaction product having a higher compressive strength in a consolidated agglomerate than the tackifier. stickiness alone with the articulated ρ. In this case, the non-aqueous tackifier may function similarly to a hardenable resin. Multifunctional materials suitable for use in the present invention include, but are not limited to,

13

c 23 l

are limited to aldehydes such as formaldehyde, dialdehydes such as glutaraldehyde, hemiacetals or aldehyde releasing compounds, diacid halides, dialects such as dichlorides and dibromides, polyacid anhydrides such as citric acids, epoxides, furfiiraldehyde, glutaraldehyde or aldehyde condensates and the like and combinations thereof. In some embodiments of the present invention, the multifunctional material may be mixed with the tackifier in an amount from about 0.01 to about 50 percent by weight of the tackifier to effect reaction product formation. In some preferred embodiments, the multifunctional material is present in an amount from about 0.5 to about 1 weight percent of the tackiness compound. Suitable multifunctional materials are described in U.S. Patent No. 5,839,510, the relevant disclosure of which is incorporated herein by reference.

Suitable solvents for use with non-aqueous tackifiers include any solvent that is compatible with the non-aqueous tackifier and achieves the desired viscosity effect. Solvents which may be used in the present invention preferably include those having high flash points (more preferably above about 125 ° F (52 ° C)). Examples of solvents suitable for use in the present invention include, but are not limited to, butyl glycidyl ether, dipropylene glycol methyl ether, butyl residual alcohol, dipropylene glycol dimethyl ether, diethylene glycol methyl ether, ethylene glycol butyl ether, methanol, butyl alcohol, isopropyl alcohol, diethylene glycol butyl ether, propylene carbonate, d-limonene, 2-butoxy ethanol, butyl acetate, furfuryl acetate, butyl lactate, dimethyl sulfoxide, dimethyl formamide, methyl acid esters fat and combinations thereof. It is within the ability of a person skilled in the art, with the benefit of this disclosure, to determine whether a solvent is required to achieve a viscosity suitable for underground conditions and, if so, how much. Aqueous tackifiers suitable for use in the present invention are not significantly tacky when placed in a particulate, but are capable of being "activated" (i.e. destabilized, coalesced and / or reacted) to transform the compound into a compound. sticky, sticky at a desirable time. Such activation may occur before, during, or after the aqueous sticky agent is placed in the underground formation. In some embodiments, a pretreatment may first be contacted with the surface of a particulate to prepare it to be coated with an aqueous tackifier. Suitable aqueous tackifiers are generally charged polymers comprising compounds which, when in an aqueous solvent or solution, will form a non-hardening coating (either alone or with an activator and / or catalyst) and, when placed in a particulate, increase the continuous critical suspension rate of particulate when counted by a stream of water. The aqueous tackifier can enhance grain-to-grain contact between individual particles within the formation (these are holding particles, forming fines, or other particles), helping it to consolidate the particles into an adherent, flexible mass. and permeable. When used, the activator and / or catalyst may be a component of a treatment fluid comprising the aqueous tackifier or may be introduced into the underground formation separately via the dynamic offset tool (e.g. as a a treatment fluid) or by some other means (for example, pumped into the surface ring).

Examples of aqueous tackifiers suitable for use in the present invention include, but are not limited to, acrylic acid polymers, acrylic acid polymers, acrylic acid derived polymers, acrylic acid homopolymers, ester esters homopolymers.

3J

acrylic acid (such as poly (methyl acrylate), poly (butyl acrylate) and, poly (2-ethylhexyl acrylate)), acrylic acid ester copolymers, methacrylic acid derived polymers, acid homopolymers methacrylic acid, methacrylic acid ester homopolymers (such as 5-poly (methyl methacrylate), poly (butyl methacrylate) and poly (2-ethylhexyl methacrylate)), propane acrylamide methyl sulfonate polymers, polymers propane acrylamide methyl sulfonate derivatives, propane acrylamide methyl sulfonate copolymers and propane acrylic acid / acrylamide methyl sulfonate copolymers and combinations thereof. The term "derivative" is defined herein to include any compound that is manufactured from one of the listed compounds, for example by replacing an atom in one of the listed compounds with another atom or group of atoms, ionizing one of the compounds. listed or by creating a salt of one of the listed compounds. Methods of determining suitable aqueous tackifiers and further disclosure of aqueous tackifiers can be found in US Patent Application No. 10 / 864,061, filed June 9, 2004, and US Patent Application Number 10 / 864,618 filed on June 9, 2004, the relevant disclosures of which are hereby incorporated by reference. Suitable silyl modified polyamide compounds

for use in the tackifiers of the methods of the present invention may be described as substantially self-hardening compositions which are capable of at least partially adhering to the unhardened particles and which are further capable of self-hardening. to a substantially non-sticky state to which individual particulates such as forming fines will not adhere, for example, to the formation or bottlenecks of the supporting filler pore. Such silyl modified polyamides may be based, for example, on the reaction product of a silylating compound with a polyamide or polyamide mixture. The polyamide or polyamide mixture may be one or more polyamide intermediate compounds obtained, for example, from reacting a polyacid (e.g. diacid or higher) with a polyamine (e.g. diamine or higher) to form a polymer. of * 5 polyamide with the elimination of water. Other suitable silyl modified polyamides and methods of manufacturing such compounds are described in U.S. Patent No. 6,439,309, the relevant disclosure of which is incorporated herein by reference.

Some suitable tackifiers are described in U.S. Patent No. 5,249,627 by Harms, et al., The relevant disclosure of which is incorporated by reference. Harms discloses aqueous tackifiers comprising at least one member selected from the group consisting of benzyl coco di- (hydroxyethyl) quaternary amine, formaldehyde-condensed pT-amylphenol, and a copolymer comprising from about 80% to about 100% C1-30 alkyl methacrylate monomers and from about 0% to about 20% hydrophilic monomers. In some embodiments, the aqueous tackifier may comprise a copolymer comprising from about 90% to about 99.5% 2-ethylexyl acrylate and from about 0.5% to about 10% acid. acrylic. Suitable hydrophilic monomers may be any monomer which will provide polar oxygen-containing or nitrogen-containing groups. Suitable hydrophilic monomers include dialkyl amino alkyl (meth) acrylates and their quaternary and acid addition salts, acrylamide, N- (dialkyl amino alkyl) acrylamide, methacrylamides and their quaternary and acid addition salts, hydroxy alkyl (meth) acrylates, unsaturated carboxylic acids such as methacrylic acid or preferably acrylic acid, hydroxyethyl acrylate, acrylamide and the like. These copolymers may be manufactured by any suitable emulsion polymerization technique. Methods of producing these copolymers are disclosed, for example, in U.S. Patent

No. 4,670,501, the relevant disclosure of which is incorporated herein by reference.

C. Formulated Net Compositions GeI

Gel-forming liquid compositions suitable for use in the methods of the present invention may comprise any gel-forming liquid composition capable of becoming a gel-forming substance capable of substantially buffering the permeability of the formation while allowing That is, the gel-forming substance must negatively compress the ability of the formation to produce desirable fluids such as hydrocarbons. As discussed above, the permeability of the formation can be restored through the use of a formation fluid. postwash or fracture through the consolidated portion As referred to herein, the term "flexible" refers to a state in which the treated formation or material is relatively malleable and elastic and capable of withstanding the substantial pressure cycle without substantial decomposition. Thus, the resulting gelable substance it must be a semi-solid, immobile gel-like substance which, among other things, stabilizes the treated portion of the formation while allowing the formation to absorb the stresses created during the pressure cycle. As a result, the gelable substance can assist in preventing formation decomposition by both stabilization and adding flexibility to sandy formations. Examples of suitable gelable liquid compositions include, but are not limited to, resin compositions which cure to form flexible gels, aqueous gelable silicate compositions, crosslinkable polymeric aqueous compositions, and polymerizable organic monomeric compositions.

Certain embodiments of the gelable liquid compositions comprise curable resin compositions. Curable resin compositions are well known to those skilled in the art and have been used to consolidate portions of unconsolidated formations and to consolidate permeable, hard mass support materials. Although the curable resin compositions used in accordance with the present invention may be similar to those previously used to consolidate permeable sand and hard mass support, they are distinct from resins suitable for use with the present invention do not cure into permeable hard masses; they preferably cure in flexible gelable substances. That is, suitable curable resin compositions form resilient gel-forming substances between the particulates of the treated portion of the unconsolidated formation and thereby allow the formation portion to remain flexible and to resist decomposition. It is not necessary or desirable for the cured resin composition to solidify and harden to provide high consolidating power to the treated portion of the formation. In contrast, upon curing, the curable resin compositions useful in accordance with this invention form immovable, semi-solid, gel-forming substances.

Generally, curable resin compositions useful in accordance with the present invention may comprise a curable resin, a diluent, and a resin curing agent. When certain resin curing agents, such as polyamides, are used in curable resin compositions, the compositions form the immovable, semi-solid, gel-forming substances described above. Where the resin-curing agent used may induce the organic resin compositions to form hard, brittle material rather than a desired gelable substance, the curable resin compositions may further comprise one or more "softening additives" (described below). more details below) to provide flexibility to cured compositions.

Examples of curable resins that may be used in the curable resin compositions of the present invention include, but are not limited to, organic resins, such as polyepoxide resins (e.g. bisphenol A-epichlorohydrin resins), polyester resins, urea-aldehyde resins, furan resins, urethane resins, and mixtures thereof. Of these, polyepoxide resins are preferred.

Any diluent that is compatible with the curable resin and achieves the desired viscosity effect is suitable for use in the present invention. Examples of diluents that may be used in the curable resin compositions of the present invention include, but are not limited to, phenols; formaldehydes; furfuryl alcohols; furfurals; alcohols; ethers, such as butyl glycidyl ether and cresyl glycidyl ether etherphenyl glycidyl ether; and mixtures thereof. In some embodiments of the present invention, the diluent comprises butyl lactate. The diluent may be used to reduce the viscosity of the curable resin composition to about 3 to about 3,000 centipoises ("0") at 80 ° F (27 ° C). Among other things, the thinner acts to provide flexibility to the cured composition. The diluent may be included in the curable resin composition in an amount sufficient to provide the desired viscosity effect. Generally, the diluent used is included in the curable resin composition in the amount of about 5% to about 75% by weight of the curable resin.

Generally, any resin curing agent that can be used to cure an organic resin is suitable for use in the present invention. When the resin curing agent of choice is an amide or polyamide, generally no flexibilizing additives will be required because, inter alia, such curing agents induce the curable resin composition to become a semi-solid, gel-forming substance. immobile. Other suitable resin curing agents (such as an amine, polyamine, methylene dianiline and other curing agents known in the art) will tend to cure into a hard, brittle material and thereby

Will benefit from the addition of a flexible additive. Generally, the resin curing agent used is included in the curable resin composition, whether or not a flexibilizing additive is included, in an amount in the range of from about 5% to about 75% by weight of the curable resin. In some embodiments of the present invention, the resin curing agent used is included in the curable resin composition in an amount ranging from about 20% to about 75% by weight of the curable resin.

As noted above, flexible additives may be used, inter alia, to provide flexibility to the gelable substances formed from curable resin compositions. The term "flexible additive" is defined herein to include any substance capable of imparting flexibility properties (e.g., suppleness, elasticity) to the gelable substances formed from curable resin compositions. Flexibilizing additives should be used where the resin curing agent of choice would induce the organic resin composition to cure into a hard and brittle material rather than the gelable substances desired herein. For example, flexible additives may be used where the resin curing agent of choice is not an amide or polyamide. Examples of suitable flexible additives include, but are not limited to, an organic ester, an oxygenated organic solvent, an aromatic solvent and combinations thereof. Of these, ethers, such as dibutyl phthalate, are preferred. Where used, the flexible additive may be included in the curable resin composition in an amount in the range of from about 5% to about 80% by weight of the curable resin. In some embodiments of the present invention, the flexible additive may be included in the curable resin composition in an amount ranging from about 20% to about 45% by weight of the curable resin.

In other embodiments, the liquid compositions

Gelable materials may comprise an aqueous gelable silicate composition. Generally, aqueous gelable silicate compositions which are useful according to the present invention generally comprise an aqueous alkali metal silicate solution and a temperature activated catalyst for the formation of aqueous alkali metal silicate solution. .

The aqueous alkali metal silicate solution component of aqueous gelable silicate compositions generally comprises an aqueous liquid and an alkali metal silicate. The aqueous liquid component of the aqueous alkali metal silicate solution may generally be freshwater, saltwater (e.g., water containing one or more salts dissolved in it), brine (e.g. saturated saltwater), seawater or, any other aqueous liquid not reacting adversely with the other components used in accordance with this invention or underground formation. Examples of suitable alkali metal silicates include, but are not limited to, one or more of sodium silicate, potassium silicate, lithium rubidium silicate or cesium silicate. Of these, sodium silicate is preferred. While sodium silicate exists in many forms, the sodium silicate used in the aqueous alkali metal silicate solution preferably has a weight ratio of Na 2 O to SiO 2 in the range from about 1: 2 to about 1: 4. More preferably, the sodium silicate used has a weight ratio of Na 2 O to SiO 2 in the range of about 1: 3.2. Generally, alkali metal silicate is present in the aqueous alkali metal silicate solution component in an amount ranging from about 0.1% to about 10% by weight of the aqueous alkali metal silicate component.

The temperature-activated catalyst component of aqueous gelable silicate compositions is used, inter alia, to convert aqueous gelable silicate compositions into

38

w / 32% desired immovable, semi-solid, gel-forming substance described above. Selection of a temperature activated catalyst is related, at least in part, to the temperature of the underground formation to which the aqueous gelable silicate composition will be introduced. The temperature activated catalysts that may be used in the aqueous gelable silicate compositions of the present invention include, but are not limited to, ammonium sulfate, which is most suitable in the range of about 60 ° F (16 ° C). C) at about 240 ° F (116 ° C); sodium acid pyrophosphate, which is most suitable in the range of about 60 ° F (16 ° C) to about 240 ° F (116 ° C); citric acid, which is most suitable in the range of about 60 ° F (16 ° C) to about 120 ° F; and ethyl acetate, which is most suitable in the range of about 60 ° F (16 ° C) to about 120 ° F. Generally, the temperature activated catalyst is present in the range of from about 0.1% to about 5% by weight of the aqueous gelable silicate composition. When used, the temperature activated catalyst may be a component of a treatment fluid comprising the aqueous gelable silicate composition or may be introduced into the underground formation separately via the dynamic offset tool (e.g., as a component of a treatment fluid) or by some other means (e.g. pumped into the surface ring).

In other embodiments, the gelable liquid compositions may comprise crosslinkable polymeric aqueous compositions. Generally, suitable crosslinkable polymeric aqueous compositions may comprise an aqueous solvent, a crosslinkable polymer and a crosslinking agent.

The aqueous solvent may be any aqueous solvent wherein the crosslinkable composition and cross-linking agent may be dissolved, mixed, suspended or dispersed therein to facilitate gel formation. For example, the aqueous solvent used may be fresh water, water 33 JCO << s

brine, brine, seawater or any other aqueous liquid not reacting adversely with the other components used in accordance with this invention or with underground formation.

Examples of crosslinkable polymers that may be used in crosslinkable polymeric aqueous compositions include, but are not limited to, carboxylate-containing polymers and acrylamide-containing polymers. Preferred acrylamide-containing polymers include polyacrylamide, partially hydrolyzed polyacrylamide, acrylamide and acrylate copolymers, and carboxylate-containing terpolymers and acrylate tetrapolymers. Additional examples of suitable crosslinkable polymers include hydratable polymers comprising polysaccharides and derivatives thereof and which contain one or more of the galactose, mannose, glycoside, glucose, xylose, arabinose, fructose, glucuronic acid or pyranosyl sulfate units. Suitable natural hydratable polymers include, but are not limited to, guar gum, locust bean gum, tara, konjak, tamarind, starch, cellulose, caraia, xanthan, tragacanth, and carrageenan, and derivatives of all of the above. Suitable hydratable synthetic polymers and copolymers which may be used in crosslinkable polymeric aqueous compositions include, but are not limited to, polyacrylates, polymethacrylates, polyacrylamides, maleic anhydride, methyl vinyl ether polymers, polyvinyl alcohols and polyvinylpyrrolidone. The crosslinkable polymer used should be included in the crosslinkable polymeric aqueous composition in an amount sufficient to form the desired gelable substance in the underground formation. In some embodiments of the present invention, the crosslinkable polymer is included in the crosslinkable polymeric aqueous composition in an amount ranging from about 1% to about 30% by weight of the aqueous solvent. In another embodiment of the present invention, the crosslinkable polymer is included in the crosslinkable polymeric aqueous composition in an amount ranging from about 1% to about 20% by weight of the aqueous solvent.

The crosslinkable polymeric aqueous compositions of the present invention may further comprise a crosslinking agent for crosslinking the crosslinkable polymers to form the desired gelable substance. In some embodiments, the crosslinking agent may be a molecule or complex containing a reactive transition metal cation. A more preferred crosslinking agent comprises complexed or anion-linked trivalent chromium cations, atomic oxygen or water. Examples of suitable crosslinking agents include, but are not limited to, compounds or complexes containing chromic acetate and / or chromic chloride. Other suitable transition metal cations include chromium VI within a redox system, aluminum III, iron II, iron III and zirconium IV.

The crosslinking agent should be present in the crosslinkable polymeric aqueous compositions of the present invention in an amount sufficient to provide, inter alia, the desired degree of crosslinking. In some embodiments of the present invention, the crosslinking agent is present in the crosslinkable polymeric aqueous compositions of the present invention in an amount ranging from 0.01% to about 5% by weight of the crosslinkable polymeric aqueous composition. The exact type and amount of crosslinking agent or agents used depends on the specific crosslinkable polymer to be crosslinked, forming temperature conditions, and other factors known to those skilled in the art.

Optionally, cross-linkable polymeric aqueous compositions may further comprise a cross-linking delay agent, such as guar-derived polysaccharide cross-linking delay agents, guar derivatives or cellulose derivatives. The crosslinking delay agent may be included in the crosslinkable polymeric aqueous compositions, inter alia, to delay crosslinking of the crosslinkable polymeric aqueous compositions to the desired extent. One of ordinary skill in the art, with the benefit of this disclosure, will know the appropriate amount of crosslinking delay agent to include in the crosslinkable polymeric aqueous compositions for a desired application. In other embodiments, the liquid compositions

gelable compositions may comprise polymerizable organic monomeric compositions. Generally, suitable polymerizable organic monomer compositions may comprise an aqueous based fluid, a water soluble polymerizable organic monomer, an oxygen decontaminant and a primary initiator.

The aqueous based fluid component of the polymerizable organic monomer composition can generally be freshwater, saltwater, brine, seawater or any other aqueous liquid that does not adversely react with the other components used in accordance with this invention or the invention. underground formation.

A variety of monomers are suitable for use as the water soluble polymerizable organic monomers of the present invention. Examples of suitable monomers include, but are not limited to, acrylic acid, methacrylic acid, acrylamide, methacrylamide, 2-methacrylamido-2-methylpropane sulfonic acid, 2-dimethylacrylamide, vinyl sulfonic acid, α, β-dimethylaminoethyl methacrylate, 2-triethylammonium -methyl methacrylate chloride, Ν, Ν-dimethyl-aminopropylmethacrylamide, methacrylamidepropyltriethylammonium chloride, N-vinyl pyrrolidone, vinylphosphonic acid, and methacryloyloxyethyl trimethylammonium sulfate and mixtures thereof. Preferably, the water soluble polymerizable organic monomer should be self-crosslinking. Examples of suitable monomers that are self-crosslinking include, but are not limited to, hydroxyethylacrylate, hydroxymethylacrylate, hydroxyethyl methacrylate, N-hydroxymethylacrylamide, N-hydroxymethyl methacrylamide, polyethylene glycol acrylate, polyethylene glycolyl methacrylate acrylate, polypropylene glycol and mixtures thereof. Of these, hydroxyethyl acrylate is preferred. An example of a particularly preferred monomer is hydroxyethylcellulose-vinyl phosphoric acid. * 5 Water-soluble polymerizable organic monomer (or

monomers where a mixture of these is used) must be included in the polymerizable organic monomer composition in an amount sufficient to form the desired gelable substance after placement of the polymerizable organic monomer composition in the underground formation. In some embodiments of the present invention, the water soluble polymerizable organic monomer (s) is included in the polymerizable organic monomer composition in an amount in the range of about 1% to about 30% by weight of the aqueous based fluid. In another embodiment of the present invention, the water soluble polymerizable organic monomer (s) is included in the polymerizable organic monomer composition in an amount in the range from about 1% to about 20% by weight of the aqueous based fluid.

The presence of oxygen in the polymerizable organic monomer composition may inhibit the polymerization process of the water soluble polymerizable organic monomer or monomers. Therefore, an oxygen decontaminant such as stannous chloride may be included in the polymerizable monomer composition. In order to improve the solubility of stannous chloride so that it can be easily combined with the fly polymerizable monomeric composition, stannous chloride may be pre-dissolved in a hydrochloric acid solution. For example, stannous chloride may be dissolved in a 0.1 wt% aqueous hydrochloric acid solution in an amount of about 10 wt% of the resulting solution. The resulting stannous chloride-hydrochloric acid solution may be

€ 3 is included in the polymerizable organic monomer composition in an amount ranging from about 0.1% to about 10% by weight of the polymerizable organic monomer composition. Generally, stannous chloride may be included in the polymerizable organic monomeric composition of the present invention in an amount ranging from about 0.005% to about 0.1% by weight of the polymerizable organic monomeric composition.

The primary initiator is used, inter alia, to initiate polymerization of the water soluble polymerizable organic monomer (s) used in the present invention. Any compound or compounds which form free radicals in the aqueous solution may be used as the primary initiator. Free radicals act, inter alia, to initiate polymerization of the soluble polymerizable organic monomer (s)

s

in water present in the polymerizable organic monomer composition. Suitable compounds for use as the primary initiator include, but are not limited to, alkali metal persulfates; peroxides; oxidation-reduction systems using reducing agents such as sulfites in combination with oxidants; and azo polymerization initiators. Preferred azo polymerization initiators include 2,2'-azobis (2-imidazol-2-hydroxyethyl) propane, 2,2'-azobis (2-aminopropane), 4,4'-azobis (4-20 cyanovaleric) acid and 2,2'-azobis (2-methyl-N- (2-hydroxyethyl) propionamide).

Generally, the primary initiator should be present in the polymerizable organic monomer composition in an amount sufficient to initiate polymerization of the water soluble polymerizable organic monomer (s). In certain embodiments of the present invention, the primary initiator is present in the polymerizable organic monomer composition in an amount in the range of from about 0.1% to about 5% by weight of the organic monomer (s). water soluble polymerizable (s).

Optionally, the polymerizable organic monomer compositions may further comprise a secondary initiator. A secondary initiator may be used, for example, where the immature aqueous gel is placed in an underground formation that is relatively cooled as compared to the surface mix, such as when placed below the sludge line in close range operations. The secondary initiator may be any suitable water-soluble compound or compounds which may react with the primary initiator to provide free radicals at a lower temperature An example of a suitable secondary initiator is triethanolamine In some embodiments of the present In this invention, the secondary initiator is present in the polymerizable organic monomer composition in an amount in the range of from about 0.1% to about 5% by weight of the soluble polymerizable organic monomer (s). ) in water.

Optionally, the polymerizable organic monomer compositions of the present invention may further comprise a cross-linking agent for cross-linking the polymerizable organic monomer compositions to the desired gelable substance. In some embodiments, the crosslinking agent is a molecule or complex containing a reactive transition metal cation. A more preferred crosslinking agent comprises complexed or anion-linked trivalent chromium cations, atomic oxygen, or water. Examples of suitable crosslinking agents include, but are not limited to, compounds or complexes containing chromic acetate and / or chromic chloride. Other suitable transition metal cations include chromium VI within a redox system, aluminum III, iron II, iron III, and zirconium IV. Generally, the crosslinking agent may be present in the polymerizable organic monomer compositions in an amount in the range of from 0.01% to about 5% by weight of the polymerizable organic monomer composition.

Therefore, the present invention will be adapted to achieve the purposes and advantages mentioned, as well as those inherent therein. The particular embodiments disclosed above are illustrative only, as the present invention may be modified and practiced in different but equivalent ways apparent to those skilled in the art having the benefit of the teachings therein. While numerous changes may be made by those skilled in the art, such changes are included within the spirit of this invention as defined by the appended claims. In addition, no limitation is intended for the construction or design details shown herein other than those described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present invention. In particular, each range of values (for example, "from about to about b," or, equivalently, "from about aab," or, equivalently, "from about ab") disclosed herein, should be understood to refer to refers to the power set (the set of all subsets) of the respective range of values. The terms in the claims have their plan of usual meaning unless otherwise explicitly and clearly defined by the patent.

Claims (20)

Method for stabilizing portions of an underground formation comprising unconsolidated particulates, characterized in that it comprises: providing a consolidating agent; introducing the consolidating agent into an unconsolidated portion of an underground formation through a dynamic offset tool; and allowing the consolidating agent to at least partially consolidate the unconsolidated portion of the underground formation. Method according to claim 15, characterized in that the unconsolidated portion of the underground formation comprises one or more fractures within the underground formation. Method according to claim 1, characterized in that the consolidating agent is selected from the group consisting of resins, tackifiers, gel-forming liquid compositions, derivatives thereof and combinations thereof. A method according to claim 1, characterized in that the dynamic offset tool is selected from the group consisting of bored joint assemblies, hydrodetontion tools, hydroblasting tools, pulse tools and combinations thereof. The method of claim 1, wherein providing a consolidating agent comprises providing a treatment fluid comprising the consolidating agent; and introducing the consolidating agent into an unconsolidated portion of the underground formation comprises introducing the treatment fluid comprising the consolidating agent into the unconsolidated portion of an underground formation. A method according to claim 1, characterized in that the unconsolidated portion of the underground formation comprises one or more fractures within the underground formation wherein a plurality of particulates reside within the open space of one or more fractures. Method according to claim 1, characterized in that the unconsolidated portion of the underground formation comprises a plurality of unconsolidated supporting particles. A method according to claim 1, further comprising introducing a prewash fluid into a portion of the underground formation. A method according to claim 1, characterized in that it further comprises introducing an afterwash fluid into a portion of the underground formation. A method according to claim 1, characterized in that the underground formation comprises one or more casing columns, screens, gravel fillings or a combination thereof. A method according to claim 1, characterized in that it further comprises placing a static biasing agent within a portion of the underground formation. A method according to claim 1, characterized in that it further comprises pushing a fluid through the dynamic offset tool at a pressure sufficient to erode and / or fracture a portion of the underground formation. A method for stabilizing portions of an underground formation comprising unconsolidated particulates, characterized in that it comprises: providing a consolidating agent; introducing the consolidating agent into an unconsolidated portion of an underground formation by means of a dynamic offset tool, wherein a plurality of unconsolidated supporting particles reside within the underground formation; and allowing the consolidating agent to at least partially consolidate the unconsolidated supporting particulates within the unconsolidated portion of the underground formation. Method according to claim 13, characterized in that the consolidating agent is selected from the group consisting of resins, tackifiers, gel-forming liquid compositions, derivatives thereof and combinations thereof. A method according to claim 13, characterized in that it further comprises placing a static biasing agent within a portion of the underground formation. A method according to claim 13, characterized in that the unconsolidated portion of the underground formation comprises one or more fractures within the underground formation wherein the plurality of unconsolidated supporting particles reside within the open space of one or more. fractures. A method for stabilizing portions of an underground formation comprising unconsolidated particulates, characterized in that it comprises: providing a consolidating agent; introducing the consolidating agent into an unconsolidated portion of an underground formation through a dynamic offset tool, wherein a plurality of unconsolidated forming particles reside within the underground formation; and allowing the consolidating agent to at least partially consolidate the unconsolidated forming particles within the underground formation. The method according to claim 17, characterized in that the consolidating agent is selected from the group consisting of resins, tackifiers, gel-forming liquid compositions, derivatives thereof and combinations thereof. A method according to claim 17, further comprising placing a static biasing agent within a portion of the underground formation. A method according to claim 17, characterized in that the unconsolidated portion of the underground formation comprises one or more fractures within the underground formation wherein the plurality of unconsolidated forming particles reside within the open space of one or more. fractures.