Búsqueda Imágenes Maps Play YouTube Noticias Gmail Drive Más »
Iniciar sesión
Usuarios de lectores de pantalla: deben hacer clic en este enlace para utilizar el modo de accesibilidad. Este modo tiene las mismas funciones esenciales pero funciona mejor con el lector.

Patentes

  1. Búsqueda avanzada de patentes
Número de publicaciónUS20070114032 A1
Tipo de publicaciónSolicitud
Número de solicitudUS 11/285,686
Fecha de publicación24 May 2007
Fecha de presentación22 Nov 2005
Fecha de prioridad22 Nov 2005
También publicado comoCA2630319A1, CA2630319C, CN101370902A, CN101370902B, EP1963458A1, WO2007060389A1
Número de publicación11285686, 285686, US 2007/0114032 A1, US 2007/114032 A1, US 20070114032 A1, US 20070114032A1, US 2007114032 A1, US 2007114032A1, US-A1-20070114032, US-A1-2007114032, US2007/0114032A1, US2007/114032A1, US20070114032 A1, US20070114032A1, US2007114032 A1, US2007114032A1
InventoresNeil Stegent, Philip Nguyen, Kevin Halliburton, Matthew Blauch, Loyd East
Cesionario originalStegent Neil A, Nguyen Philip D, Halliburton Kevin W, Blauch Matthew E, East Loyd E Jr
Exportar citaBiBTeX, EndNote, RefMan
Enlaces externos: USPTO, Cesión de USPTO, Espacenet
Methods of consolidating unconsolidated particulates in subterranean formations
US 20070114032 A1
Resumen
Methods for stabilizing portions of a subterranean formation that comprise 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 a subterranean formation through a dynamic diversion tool; and allowing the consolidating agent to at least partially consolidate the unconsolidated portion of the subterranean formation.
Imágenes(8)
Previous page
Next page
Reclamaciones(20)
1. A method comprising:
providing a consolidating agent;
introducing the consolidating agent into an unconsolidated portion of a subterranean formation through a dynamic diversion tool; and
allowing the consolidating agent to at least partially consolidate the unconsolidated portion of the subterranean formation.
2. The method of claim 1 wherein the unconsolidated portion of the subterranean formation comprises one or more fractures within the subterranean formation.
3. The method of claim 1 wherein the consolidating agent is selected from the group consisting of resins, tackifying agents, gelable liquid compositions, derivatives thereof and combinations thereof.
4. The method of claim 1 wherein the dynamic diversion tool is selected from the group consisting of ported-sub assemblies, hydroblast tools, hydrajetting tools, pulsonic tools and combinations thereof.
5. The method of claim 1 wherein providing a consolidating agent comprises providing a treatment fluid that comprises the consolidating agent; and
introducing the consolidating agent into an unconsolidated portion of the subterranean formation comprises introducing the treatment fluid that comprises the consolidating agent into the unconsolidated portion of a subterranean formation.
6. The method of claim 1 wherein the unconsolidated portion of the subterranean formation comprises one or more fractures within the subterranean formation wherein a plurality of particulates reside within the open space of the one or more fractures.
7. The method of claim 1 wherein the unconsolidated portion of the subterranean formation comprises a plurality of unconsolidated proppant particulates.
8. The method of claim 1 further comprising introducing a preflush fluid into a portion of the subterranean formation.
9. The method of claim 1 further comprising introducing an afterflush fluid into a portion of the subterranean formation.
10. The method of claim 1 wherein the subterranean formation comprises one or more casing strings, screens, gravel-packs, or a combination thereof.
11. The method of claim 1 further comprising placing a static diverting agent within a portion of the subterranean formation.
12. The method of claim 1 further comprising propelling a fluid through the dynamic diversion tool at a pressure sufficient to erode and/or fracture a portion of the subterranean formation.
13. A method comprising:
providing a consolidating agent;
introducing the consolidating agent into an unconsolidated portion of a subterranean formation through a dynamic diversion tool, wherein a plurality of unconsolidated proppant particulates reside within the subterranean formation; and
allowing the consolidating agent to at least partially consolidate the unconsolidated proppant particulates within the unconsolidated portion of the subterranean formation.
14. The method of claim 13 wherein the consolidating agent is selected from the group consisting of resins, tackifying agents, gelable liquid compositions, derivatives thereof and combinations thereof.
15. The method of claim 13 further comprising placing a static diverting agent within a portion of the subterranean formation.
16. The method of claim 13 wherein the unconsolidated portion of the subterranean formation comprises one or more fractures within the subterranean formation wherein the plurality of unconsolidated proppant particulates reside within the open space of the one or more fractures.
17. A method comprising:
providing a consolidating agent;
introducing the consolidating agent into an unconsolidated portion of a subterranean formation through a dynamic diversion tool, wherein a plurality of unconsolidated formation particulates reside within the subterranean formation; and
allowing the consolidating agent to at least partially consolidate the unconsolidated formation particulates within the subterranean formation.
18. The method of claim 17 wherein the consolidating agent is selected from the group consisting of resins, tackifying agents, gelable liquid compositions, derivatives thereof and combinations thereof.
19. The method of claim 17 further comprising placing a static diverting agent within a portion of the subterranean formation.
20. The method of claim 17 wherein the unconsolidated portion of the subterranean formation comprises one or more fractures within the subterranean formation wherein the plurality of unconsolidated formation particulates reside within the open space of the one or more fractures.
Descripción
    BACKGROUND
  • [0001]
    The present invention relates to the treatment of subterranean formations. More particularly, the present invention relates to methods for stabilizing portions of a subterranean formation that comprise unconsolidated particulates.
  • [0002]
    Hydrocarbon wells are often located in subterranean formations that contain unconsolidated particulates (e.g., sand, gravel, proppant, fines, etc.) that may migrate out of the subterranean formation into a well bore and/or may be produced with the oil, gas, water, and/or other fluids produced by the well. The presence of such particulates, in produced fluids is undesirable in that the particulates may abrade pumping and other producing equipment and/or reduce the production of desired fluids from the well. Moreover, particulates that have migrated into a well bore (e.g., inside the casing and/or perforations in a cased hole), among other things, may clog portions of the well bore, hindering the production of desired fluids from the well. The term “unconsolidated particulates,” and derivatives thereof, is defined herein to include loose particulates and particulates bonded with insufficient bond strength to withstand the forces created by the production of fluids through the formation. Unconsolidated particulates may comprise, among other things, sand, gravel, fines and/or proppant particulates in the subterranean formation, for example, proppant particulates placed in the subterranean formation in the course of a fracturing or gravel-packing operation. The terms “unconsolidated subterranean formations,” “unconsolidated portions of a subterranean formation,” and derivatives thereof are defined herein to include any formations that contain unconsolidated particulates, as that term is defined herein. “Unconsolidated subterranean formations,” and “unconsolidated portions of a subterranean formation,” as those terms are used herein, include subterranean fractures wherein unconsolidated particulates reside within the open space of the fracture (e.g., forming a proppant pack within the fracture).
  • [0003]
    One method of controlling unconsolidated particulates in subterranean formations involves placing a filtration bed containing gravel (e.g., a “gravel pack”) near the well bore to present a physical barrier to the transport of unconsolidated particulates with the production of desired fluids. Typically, such “gravel-packing operations” involve the pumping and placement of a quantity of certain particulate, into the unconsolidated subterranean formation in an area adjacent to a well bore. One common type of gravel-packing operation involves placing a screen in the well bore and packing the surrounding annulus between the screen and the well bore with gravel of a specific size designed to prevent the passage of formation sand. The screen is generally a filter assembly used to retain the gravel placed during the gravel-pack operation. A wide range of sizes and screen configurations are available to suit the characteristics of the gravel-pack sand used. Similarly, a wide range of sizes of gravel is available to suit the characteristics of the unconsolidated particulates in the subterranean formation. To install the gravel pack, the gravel is carried to the formation in the form of a slurry by mixing the gravel with a fluid, which is usually viscosified. Once the gravel is placed in the well bore, the viscosity of the treatment fluid may be reduced, and it is returned to the surface. The resulting structure presents a barrier to migrating sand from the formation while still permitting fluid flow.
  • [0004]
    However, the use of such gravel-packing methods may be problematic. For example, gravel packs may be time consuming and expensive to install. Due to the time and expense needed, it is sometimes desirable to place a screen without the gravel. Even in circumstances in which it is practical to place a screen without gravel, it is often difficult to determine an appropriate screen size to use as formation sands tend to have a wide distribution of grain sizes. When small quantities of sand are allowed to flow through a screen, formation erosion becomes a significant concern. As a result, the placement of gravel as well as the screen is often necessary to assure that the formation sands are 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 well bore, cased hole, or open hole for sand control purposes without the need for gravel packing. However, expandable screens may still exhibit such problems as screen erosion and screen plugging.
  • [0005]
    Another method used to control unconsolidated particulates in subterranean formations involves consolidating unconsolidated particulates into stable, permeable masses by applying a consolidating agent (e.g., a resin or tackifying agent) to the subterranean formation. However, it may be desirable in some cases to preferentially place a consolidating agent in a particular region of a subterranean formation (e.g., an unconsolidated portion) penetrated by a well bore. To place the consolidating agent in a specific region of a subterranean formation, certain types of isolation tools, such as “pack off” devices, packers, gel plugs, mechanical plugs, bridge plugs, ball sealers, and the like, have been used in the art to isolate certain intervals of a subterranean formation and place a consolidating agent in a region of the subterranean formation in that interval. However, the use of these isolation tools may be problematic. First, in applications where it is desirable to treat multiple regions of a subterranean formation in multiple different intervals, the isolation tools used must be removed and repositioned to isolate subsequently treated intervals, a process which may, among other things, risk damage to the subterranean formation and/or the well bore, and increase the cost, complexity, and duration of the operation. Moreover, in methods employing these isolation tools, some amount of the consolidating agent and/or associated treatment fluid(s) introduced into the subterranean formation usually “leak” into regions of the subterranean formation outside of the isolated interval, and thus those methods generally require larger amounts of consolidating agent (and/or the treatment fluid carrying the consolidating agent) to ensure that the isolated interval of the subterranean formation is completely treated.
  • SUMMARY
  • [0006]
    The present invention relates to the treatment of subterranean formations. More particularly, the present invention relates to methods for stabilizing portions of a subterranean formation that comprise unconsolidated particulates.
  • [0007]
    In one embodiment, the present invention provides a method comprising: providing a consolidating agent; introducing the consolidating agent into an unconsolidated portion of a subterranean formation through a dynamic diversion tool; and allowing the consolidating agent to at least partially consolidate the unconsolidated portion of the subterranean formation.
  • [0008]
    In another embodiment, the present invention provides a method comprising: providing a consolidating agent; introducing the consolidating agent into an unconsolidated portion of a subterranean formation through a dynamic diversion tool, wherein a plurality of unconsolidated proppant particulates reside within the subterranean formation; and allowing the consolidating agent to at least partially consolidate the unconsolidated proppant particulates within the unconsolidated portion of the subterranean formation.
  • [0009]
    In another embodiment, the present invention provides a method comprising: providing a consolidating agent; introducing the consolidating agent into an unconsolidated portion of a subterranean formation through a dynamic diversion tool, wherein a plurality of unconsolidated formation particulates reside within the subterranean formation; and allowing the consolidating agent to at least partially consolidate the unconsolidated formation particulates within the subterranean formation.
  • [0010]
    The features and advantages of the present invention will be apparent to those skilled in the art. While numerous changes may be made by those skilled in the art, such changes are within the spirit of the invention.
  • BRIEF DESCRIPTION OF THE DRAWINGS
  • [0011]
    These drawings illustrate certain aspects of some of the embodiments of the present invention, and should not be used to limit or define the invention.
  • [0012]
    FIG. 1 illustrates a side view of a subterranean formation that may be treated in certain embodiments of the present invention.
  • [0013]
    FIG. 2 illustrates a side view of a subterranean formation being treated during the course of one embodiment of the present invention.
  • [0014]
    FIG. 3 illustrates a side view of a subterranean formation being treated during the course of one embodiment of the present invention.
  • [0015]
    FIG. 4 illustrates a side view of a subterranean formation being treated during the course of one embodiment of the present invention.
  • [0016]
    FIG. 5 illustrates a side view of a subterranean formation being treated during the course of one embodiment of the present invention.
  • [0017]
    FIG. 6 illustrates a side view of a subterranean formation being treated during the course of one embodiment of the present invention.
  • [0018]
    FIG. 7 illustrates a side view of a subterranean formation that has been treated in the course of one embodiment of the present invention.
  • DESCRIPTION OF PREFERRED EMBODIMENTS
  • [0019]
    The present invention relates to the treatment of subterranean formations. More particularly, the present invention relates to methods for stabilizing portions of a subterranean formation that comprise unconsolidated particulates.
  • I. METHODS OF THE PRESENT INVENTION
  • [0020]
    The methods of the present invention generally comprise: providing a consolidating agent; introducing the consolidating agent into an unconsolidated portion of a subterranean formation through a dynamic diversion tool; and allowing the consolidating agent to at least partially consolidate the unconsolidated portion of the subterranean formation. The consolidating agent may be provided and/or introduced into the subterranean formation as a component of one or more treatment fluids introduced into the subterranean formation. The term “consolidating agent,” is defined herein to include any substance that may stabilize a portion of the subterranean formation, which may, at least in part, stabilize unconsolidated particulates such that they are prevented from shifting or migrating. The term “dynamic diversion tool” is defined herein to include any device that is capable of modifying (e.g., increasing) the velocity of a fluid into a subterranean formation from the velocity of that fluid in a well bore. The methods of the present invention may be used to at least partially consolidate a selected interval in an unconsolidated portion of a subterranean formation without the need for isolation tools used heretofore in the art.
  • [0021]
    The subterranean formations treated in the methods of the present invention may be any subterranean formation wherein at least a plurality of unconsolidated particulates resides in the formation. An example of such a subterranean formation is illustrated in FIG. 1. A well bore 110 penetrates several different intervals of the subterranean formation depicted therein; several of the intervals comprise consolidated portions 121, 122, 123, 124, and 125, while several intervals comprise 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, fines and/or proppant particulates within the open space of one or more fractures in the subterranean formation (e.g., unconsolidated proppant particulates that form a proppant pack within the fracture). Proppant particulates may be comprised of any material suitable for use in subterranean operations. Examples include, but are not limited to, sand, bauxite, ceramic materials, glass materials (e.g., glass beads), polymer materials, Teflon® materials, nut shell pieces, seed shell pieces, cured resinous particulates comprising nut shell pieces, cured resinous particulates comprising seed shell pieces, fruit pit pieces, cured resinous particulates comprising fruit pit pieces, wood, composite particulates, and combinations thereof. Composite particulates also may be used, wherein suitable composite materials may comprise a binder and a filler material wherein suitable filler materials include silica, alumina, fumed carbon, carbon black, graphite, mica, titanium dioxide, meta-silicate, calcium silicate, kaolin, talc, zirconia, boron, fly ash, hollow glass microspheres, solid glass, ground nut/seed shells or husks, saw dust, ground cellulose fiber, and combinations thereof. Typically, the particulates have a size in the range of from about 2 to about 400 mesh, U.S. Sieve Series. In particular embodiments, particulates size distribution ranges are one or more of 6/12 mesh, 8/16, 12/20, 16/30, 20/40, 30/50, 40/60, 40/70, or 50/70 mesh. It should be understood that the term “particulate,” as used in this disclosure, includes all known shapes of materials including substantially spherical materials, fibrous materials, polygonal materials (such as cubic materials) and mixtures thereof. Moreover, fibrous materials that may be used, inter alia, to bear the pressure of a closed fracture, are often included. In some embodiments, the proppant particulates may be coated with any suitable resin or tackifying agent known to those of ordinary skill in the art.
  • [0022]
    The subterranean formations treated in the methods of the present invention may be penetrated by a well bore through which the consolidating agent and/or other treatment fluids may be introduced, for example, as shown by well bore 110 in FIG. 1. A well bore penetrating the subterranean formation being treated may contain one or more pipes or casing strings (e.g., a “cased” or “partially cased” well bore), as shown by casing 140 in well bore 110 in FIG. 1. In certain embodiments, the well bore may be uncased. In certain embodiments, a well bore penetrating the subterranean formation may contain one or more screens and/or gravel-packs, among other purposes, to decrease the migration of formation sands into the well bore. In other embodiments, the well bore may contain no such screens or gravel-packs (e.g., an “unscreened” well bore).
  • [0023]
    In those embodiments where the portion of the well bore penetrating the portion of the subterranean formation being treated is cased or partially cased, the dynamic diversion tool may introduce fluids and/or the consolidating agent into the subterranean formation by directing the through perforations or holes in the casing that allow fluid communication between the interior of the casing and the annulus (i.e., the space between the walls of the well bore and the outer surface of the casing). Referring now to FIG. 1, one or more perforations 150 may be created in the casing 140 that is set in the well bore 110 to allow fluid communication between the interior of the casing and an unconsolidated portion 134 of the subterranean formation. In certain embodiments, the dynamic diversion tool may be used to create those perforations or holes in the casing, for example, by propelling a fluid comprising abrasive materials (e.g., particulate materials such as sand, gravel, degradable particulates, and the like) at the interior surface of the casing and/or propelling a fluid at a sufficiently high pressure at the interior surface of the casing to create the perforations or holes in the casing. In other embodiments, the perforations or holes may be created using some other method or apparatus prior to or during the course of conducting a method of the present invention. In certain embodiments, particulates residing in the perforations or holes in the casing may be displaced by the consolidating agent (or the fluid comprising the consolidating agent), which may, inter alia, enhance or restore the flow of fluid through those perforations or holes in the casing.
  • [0024]
    Referring now to FIG. 2, the dynamic diversion tool 210 may be placed in the well bore with a pipe string comprising 220 coiled tubing or jointed pipe. The dynamic diversion tool 210 is placed in a portion of the well bore adjacent to an unconsolidated portion 134 of the subterranean formation. Referring now to FIG. 3, the consolidating agent may be introduced through the coiled tubing or jointed pipe 220 to the dynamic diversion tool 210, where the tool may direct the consolidating agent 320 into the unconsolidated portion 134 of the subterranean formation.
  • [0025]
    In certain embodiments, it may not be desirable to use certain types of dynamic diversion tools that are capable of propelling fluid at a pressure sufficient to erode and/or fracture a portion of the subterranean formation. However, in certain embodiments, it may be desirable to use certain types of dynamic diversion tools that are capable of propelling fluid at a pressure to sufficient to penetrate through a gravel-pack and/or screen residing in the well bore. One of ordinary skill in the art, with the benefit of this disclosure, will recognize when certain types of dynamic diversion tools are suitable or unsuitable for a particular application of the methods of the present invention, depending upon a variety of factors, including the rate and/or pressure of fluid flow desired, the structure and/or composition of the subterranean formation, the length of the interval in the subterranean formation being treated, and the like. Examples of dynamic diversion tools that may be suitable for the methods of the present invention are described in Section II. below.
  • [0026]
    The methods of the present invention may optionally include providing and introducing one or more preflush fluids into the subterranean formation at any point prior to, during, or subsequent to performing the methods of the present invention. Typically, injection of a preflush fluid may occur at any time before the consolidating agent is introduced into the subterranean formation. In certain embodiments, a preflush fluid may be applied to the subterranean formation, among other purposes, to clean out undesirable substances (e.g., oil, residue, or debris) from the pore spaces in the matrix of the subterranean formation, to clean out such undesirable substances residing in perforations or holes in a casing string, and/or to prepare the subterranean formation for later placement of the consolidating agent. For example, an acidic preflush fluid may be introduced into at least a portion of the subterranean formation that may, inter alia, dissolve undesirable substances in the subterranean formation. The preflush fluid may be introduced into the subterranean formation through the dynamic diversion tool, pumped directly into the annular space between the walls of a well bore and a casing string penetrating the subterranean formation, or introduced into the subterranean formation by any other suitable means. Generally, the volume of the preflush fluid introduced into the formation is between 0.1 times to 50 times the volume of the consolidating agent. Examples of preflush fluids suitable for use with the present invention are described in more detail in Section III.A. below.
  • [0027]
    The methods of the present invention optionally may comprise placing a static diverting agent within a portion of the subterranean formation. As used herein, the term “static diverting agent” is defined to include any static diverting agent or tool (e.g., chemicals, fluids, particulates or equipment) that is capable of diverting the flow of fluid away from a particular portion of a subterranean formation to another portion of the subterranean formation. Among other things, the static diverting agent may aid in controlling the placement of the consolidating agent in the desired area. Examples of suitable static diverting agents include, but are not limited to fluids (e.g., aqueous-base and/or non-aqueous-base fluids), emulsions, gels, foams, degradable materials (e.g., polyesters, orthoesters, poly(orthoesters), polyanhydrides, dehydrated organic and/or inorganic compounds), particulates, packers (e.g., pinpoint packers and selective injection packers), ball sealers, pack-off devices, particulates, sand plugs, bridge plugs and the like. A person skilled in the art, with the benefit of this disclosure will recognize when a static diverting agent should be used in a method of the present invention, as well as the appropriate type of placement of the static diverting agent.
  • [0028]
    The methods of the present invention may be used to consolidate a single interval in an unconsolidated portion of a subterranean formation, or may be repeated to consolidate several different intervals in a subterranean formation. Referring now to FIG. 3, for example, the dynamic diversion tool 210 initially may be positioned within a well bore so as to introduce the consolidating agent 320 into a particular interval 134 in a portion of a subterranean formation. As shown in FIG. 4, after introducing the consolidating agent 320 into that particular interval 134, the dynamic diversion tool 210 may be repositioned so as to introduce the consolidating agent 420 into another interval 133 in the subterranean formation (e.g., an interval closer to the surface than the first interval treated). As shown in FIG. 5, this process may be repeated for any number of other intervals comprising unconsolidated portions 132 and 131 of a subterranean formation, introducing the consolidating agent 520 into those portions of the subterranean formation. In embodiments where several different intervals are treated, the several intervals may be penetrated by a single well bore, different contiguous well bores, or different well bores that are not contiguous. After the treatment of one or more intervals, the dynamic diversion tool 210 then may be relocated to the bottom of the well bore 110, as shown in FIG. 5.
  • [0029]
    The methods of the present invention may optionally include providing and applying one or more afterflush fluids into the subterranean formation at any stage of the treatment process. Typically, injection of an afterflush fluid may occur at any time after the consolidating agent is introduced into the subterranean formation. When used, the afterflush fluid is preferably placed into the subterranean formation while the consolidating agent is still in a flowing state. For example, an afterflush fluid may be placed into the formation prior to a shut-in period. In certain embodiments, an afterflush fluid may be applied to the subterranean formation, among other purposes, to activate the consolidating agent, and/or to restore the permeability of a portion of the subterranean formation by displacing at least a portion of the consolidating agent from the pore channels therein or forcing the displaced portion of the consolidating agent further into the subterranean formation where it may have negligible impact on subsequent hydrocarbon production. The afterflush fluid may be introduced into the subterranean formation through the dynamic diversion tool, pumped directly into the annular space between the walls of a well bore and a casing string penetrating the subterranean formation, or introduced into the subterranean formation by any other suitable means. As shown in FIG. 6, the dynamic diversion tool 210 may be repositioned in the well bore 110 and used to circulate an afterflush fluid 660 in the well bore to restore fluid circulation in the portion of the well bore 611 and 612 adjacent to a region 133 and 134 of the subterranean formation that was consolidated in the methods of the present invention. As shown in FIG. 7, this process may be repeated for each interval until fluid circulation is restored to the entire length of the well bore 711, and the dynamic diversion tool then may be removed from the well bore. Generally, the volume of afterflush fluid introduced into the subterranean 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 afterflush fluid introduced into the subterranean formation ranges from about 0.1 times to about 5 times the volume of the consolidating agent. Examples of afterflush fluids suitable for use with the present invention are described in more detail in Section III.A. below.
  • [0030]
    The methods of the present invention may be used prior to, in combination with, or after any type of subterranean operation being performed in the subterranean formation, including but not limited to fracturing operations, gravel-packing operations, frac-packing operations (i.e., combination of fracturing and gravel-packing operations), and the like. For example, the methods of the present invention may be used at some time after a fracturing operation, wherein the methods of the present invention are used to at least partially consolidate proppant particulates placed within one or more fractures created or enhanced during the fracturing operation. In certain embodiments, the methods of the present invention optionally may comprise introducing other additives and treatment fluids, such as relative permeability modifiers, proppant, surfactants, gases, biocides, acids, or any other suitable additives or treatment fluids, into the subterranean formation through the dynamic diversion tool and/or by any other means suitable for introducing those additives or treatment fluids into the subterranean formation.
  • II. DYNAMIC DIVERSION TOOLS
  • [0031]
    The methods of the present invention utilize a dynamic diversion tool to introduce the treatment fluids into the subterranean formation. Suitable dynamic diversion tools for use in the present invention may comprise any assembly that is capable of modifying (e.g., increasing) the velocity of a fluid into a subterranean formation from the velocity of that fluid in a well bore. In certain embodiments, the dynamic diversion tool may comprise a pipe string (e.g., coiled tubing, drill pipe, etc.) with at least one port (e.g., nozzle or jet) thereon that is capable of directing the flow of fluid from within the pipe string into a subterranean formation in a desired direction. Examples of suitable dynamic diversion tools include, but are not limited to, ported subassemblies, hydroblast tools and hydrajetting tools, including those described in the following U.S. patents and patent applications, the relevant disclosures of which are incorporated herein by reference: U.S. Pat. No. 5,765,642; U.S. Pat. No. 5,249,628; U.S. Pat. No. 5,325,923; U.S. Pat. No. 5,499,678; U.S. Pat. No. 5,396,957; U.S. patent application Ser. No. 11/004,441 by East, Jr. et al. In certain embodiments, the dynamic diversion tool may comprise an acoustical tool or a pulsonic tool (e.g., a tool capable of applying a pressure pulse having a given amplitude and frequency to a fluid). Examples of suitable acoustical and pulsonic tools include, but are not limited to, fluidic oscillators, and those devices described in U.S. patent application Ser. No. 10/863,706 by Nguyen, et al., the relevant disclosure of which is incorporated herein by reference. In embodiments where the dynamic diversion tool comprises a pulsonic tool, the acoustical energy generated by the pulsonic tool may, inter alia, further stabilize the unconsolidated particulates in the subterranean formation, in conjunction with the consolidating agent used. In certain embodiments, the dynamic diversion tool may comprise an uncemented liner having jets on the outer surface of the liner.
  • [0032]
    The selection of a suitable dynamic diversion tool for a particular application of the present invention may depend upon a variety of factors, including the rate and/or pressure of fluid flow desired, the structure and/or composition of the subterranean formation, the length of the interval in the subterranean formation being treated, the particular composition of the fluid being introduced into the subterranean formation, and the like. For example, in certain embodiments, it may or may not be desirable to use certain types of dynamic diversion tools that are capable of propelling fluid at a pressure sufficient to erode and/or fracture a portion of the subterranean formation. One of ordinary skill in the art, with the benefit of this disclosure, will be able to recognize which types of dynamic diversion tools are suitable for a particular application of the methods of the present invention.
  • III. FLUIDS
  • [0033]
    In certain embodiments, the consolidating agent may be provided and/or introduced into the subterranean formation as a component of one or more treatment fluids introduced into the subterranean formation. These treatment fluids may include any fluid that does not adversely interact with the other components used in accordance with this invention or with the subterranean formation. Such treatment fluids may be aqueous-based or non-aqueous-based. Aqueous-based treatment fluids may comprise fresh water, salt water, 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 the like.
  • [0034]
    The preflush and afterflush fluids utilized 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 the subterranean formation. For example, the preflush or afterflush 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). Aqueous-based fluids may comprise fresh water, salt water, brine, or seawater, or any other aqueous fluid that does not adversely react with the other components used in accordance with this invention or with the subterranean formation. In certain embodiments, an aqueous-based preflush or afterflush fluid may comprise a surfactant. Any surfactant compatible with later-used treatments (e.g., the consolidating agent) may be used in the present invention, for example, to aid a consolidating agent in flowing 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 non-ionic surfactants, and an alkyl phosphonate surfactant. Suitable mixtures of one or more cationic and nonionic surfactants are described in U.S. Pat. No. 6,311,773, the relevant disclosure of which is incorporated herein by reference. A C12-C22 alkyl phosphonate surfactant is preferred. The surfactant or surfactants used may be included in the preflush or afterflush fluid in an amount sufficient to prepare the subterranean formation to receive a treatment of a consolidating agent. In some embodiments of the present invention, the surfactant is present in the preflush or afterflush fluid in an amount in the range of from about 0.1% to about 3% by weight of the aqueous fluid.
  • [0035]
    The treatment fluids, preflush fluids, and/or afterflush fluids utilized in methods of the present invention may comprise any number of additional additives, including, but not limited to, salts, surfactants, acids, fluid loss control additives, gas, foamers, corrosion inhibitors, scale inhibitors, catalysts, clay control agents, biocides, friction reducers, antifoam agents, bridging agents, dispersants, flocculants, H2S scavengers, CO2 scavengers, oxygen scavengers, lubricants, viscosifiers, breakers, weighting agents, relative permeability modifiers, particulate materials (e.g., proppant particulates) and the like. In certain embodiments the treatment fluids, preflush fluids, and/or afterflush fluids may comprise an activator or catalyst which may be used inter alia, to activate the polymerization of the consolidating agent. A person skilled in the art, with the benefit of this disclosure, will recognize the types of additives that may be included in the treatment fluids, preflush fluids, and/or afterflush fluids for a particular application.
  • IV. CONSOLIDATING AGENTS
  • [0036]
    Suitable consolidating agents for the methods at the present invention include any composition that may stabilize a portion of the subterranean formation, which may, at least in part, stabilize unconsolidated particulates such that they are prevented from shifting or migrating. Examples of suitable consolidating agents include resins, tackifying agents, and gelable liquid compositions.
  • [0037]
    A. Resins
  • [0038]
    Resins suitable for use as the consolidating agents in the methods of the present invention include any suitable resin that is capable of forming a hardened, consolidated mass. The term “resin” as used herein includes any of numerous physically similar polymerized synthetics or chemically modified natural resins, including but not limited to thermoplastic materials and thermosetting materials. Many such resins are commonly used in subterranean consolidation operations, and some suitable resins include two component epoxy based resins, novolak resins, polyepoxide resins, phenol-aldehyde resins, urea-aldehyde resins, urethane resins, phenolic resins, furan resins, furan/furfuryl alcohol resins, phenolic/latex resins, phenol formaldehyde resins, polyester resins and hybrids and copolymers thereof, polyurethane resins and hybrids and copolymers thereof, acrylate resins, and mixtures thereof. Some suitable resins, such as epoxy resins, may be cured with an internal catalyst or activator so that when pumped downhole, they may be cured using only time and temperature. Other suitable resins, such as furan resins, may be formulated to cure at a delayed rate, or require a time-delayed catalyst or an external catalyst to help activate the polymerization of the resins if the cure temperature is low (i.e., less than 250° F.) but will cure under the effect of time and temperature if the formation temperature is above about 250° F., preferably above about 300° F. Such external catalysts may be introduced into the subterranean formation through the dynamic diversion tool (e.g., as a component of a treatment fluid) and/or by some other means (e.g., pumped into the annulus from the surface). It is within the ability of one skilled in the art, with the benefit of this disclosure, to select a suitable resin for use in embodiments of the present invention and to determine whether a catalyst is required to trigger curing.
  • [0039]
    Selection of a suitable resin may be affected by the temperature of the subterranean formation to which the fluid will be introduced. By way of example, for subterranean formations having a bottom hole static temperature (“BHST”) ranging from about 60° F. to about 250° F., two-component epoxy-based resins comprising a hardenable resin component and a hardening agent component containing specific hardening agents may be preferred. For subterranean formations having a BHST ranging from about 300° F. to about 600° F., a furan-based resin may be preferred. For subterranean formations having a BHST ranging from about 200° F. to about 400° F., either a phenolic-based resin or a one-component HT epoxy-based resin may be suitable. For subterranean formations having a BHST of at least about 175° F., a phenol/phenol formaldehyde/furfuryl alcohol resin may also be suitable.
  • [0040]
    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 having high flash points (e.g., about 125° F.) because of, among other things, environmental and safety concerns; such solvents include butyl lactate, butylglycidyl ether, dipropylene glycol methyl ether, dipropylene glycol dimethyl ether, dimethyl form amide, diethyleneglycol methyl ether, ethyleneglycol butyl ether, diethyleneglycol butyl ether, propylene carbonate, methanol, butyl alcohol, 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 glycol 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, mono ethers of dihydric alkanols, methoxypropanol, butoxyethanol, hexoxyethanol, and isomers thereof. Selection of an appropriate solvent is dependent on the resin chosen and is within the ability of one skilled in the art with the benefit of this disclosure.
  • [0041]
    B. Tackifying Agents
  • [0042]
    Tackifying agents suitable for use in the methods of the present invention exhibit a sticky character and, thus, impart a degree of consolidation to unconsolidated particulates in the subterranean formation. The term “tackifying agent” is defined herein to include any composition having a nature such that it is (or may be activated to become) somewhat sticky to the touch. In certain embodiments, the tackifying agent may be formulated such that it is “activated” at a delayed rate, by contact with a catalyst or activator, or at certain conditions (e.g., temperature). Examples of suitable tackifying agents suitable for use in the present invention include non-aqueous tackifying agents, aqueous tackifying agents, and silyl-modified polyamides.
  • [0043]
    One type of tackifying agent suitable for use in the present invention is a non-aqueous tackifying agent. An example of a suitable tackifying agent may comprise polyamides that are liquids or in solution at the temperature of the subterranean formation such that they are, by themselves, non-hardening when introduced into the subterranean formation. One example of such a tackifying agent 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 containing some trimer and higher oligomers and also small amounts of monomer acids that are reacted with polyamines. Other polyacids include trimer acids, synthetic acids produced from fatty acids, maleic anhydride, acrylic acid, and the like. Such acid compounds are commercially available from companies such as Witco Corporation, Union Camp, Chemtall, and Emery Industries. The reaction products are available from, for example, Champion Technologies, Inc. and Witco Corporation. Additional compounds which may be used as non-aqueous tackifying agents include liquids and solutions of, for example, polyesters, polycarbonates and polycarbamates, natural resins such as shellac and the like. Other suitable non-aqueous tackifying agents are described in U.S. Pat. Nos. 5,853,048 and 5,833,000, the relevant disclosures of which are herein incorporated by reference.
  • [0044]
    Non-aqueous tackifying agents suitable for use in the present invention may be either used such that they form non-hardening coating, or they may be combined with a multifunctional material capable of reacting with the non-aqueous tackifying agent to form a hardened coating. A “hardened coating,” as used herein, means that the reaction of the tackifying agent with the multifunctional material will result in a substantially non-flowable reaction product that exhibits a higher compressive strength in a consolidated agglomerate than the tackifying agent alone with the particulates. In this instance, the non-aqueous tackifying agent may function similarly to a hardenable resin. Multifunctional materials suitable for use in the present invention include, but are not limited to, aldehydes such as formaldehyde, dialdehydes such as glutaraldehyde, hemiacetals or aldehyde releasing compounds, diacid halides, dihalides such as dichlorides and dibromides, polyacid anhydrides such as citric acid, epoxides, furfuraldehyde, 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 tackifying agent in an amount of from about 0.01 to about 50 percent by weight of the tackifying agent to effect formation of the reaction product. In some preferable embodiments, the multifunctional material is present in an amount of from about 0.5 to about 1 percent by weight of the tackifying compound. Suitable multifunctional materials are described in U.S. Pat. No. 5,839,510, the relevant disclosure of which is herein incorporated by reference.
  • [0045]
    Solvents suitable for use with non-aqueous tackifying agents include any solvent that is compatible with the non-aqueous tackifying agent and achieves the desired viscosity effect. The solvents that can be used in the present invention preferably include those having high flash points (most preferably above about 125° F.). Examples of solvents suitable for use in the present invention include, but are not limited to, butylglycidyl ether, dipropylene glycol methyl ether, butyl bottom alcohol, dipropylene glycol dimethyl ether, diethyleneglycol methyl ether, ethyleneglycol butyl ether, methanol, butyl alcohol, isopropyl alcohol, diethyleneglycol butyl ether, propylene carbonate, d-limonene, 2-butoxy ethanol, butyl acetate, furfuryl acetate, butyl lactate, dimethyl sulfoxide, dimethyl formamide, fatty acid methyl esters, and combinations thereof. It is within the ability of one skilled in the art, with the benefit of this disclosure, to determine whether a solvent is needed to achieve a viscosity suitable to the subterranean conditions and, if so, how much.
  • [0046]
    Aqueous tackifying agents suitable for use in the present invention are not significantly tacky when placed onto a particulate, but are capable of being “activated” (that is, destabilized, coalesced, and/or reacted) to transform the compound into a sticky, tackifying compound at a desirable time. Such activation may occur before, during, or after the aqueous tackifier agent is placed in the subterranean formation. In some embodiments, a pretreatment may be first contacted with the surface of a particulate to prepare it to be coated with an aqueous tackifying agent. Suitable aqueous tackifying agents are generally charged polymers that comprise compounds that, when in an aqueous solvent or solution, will form a non-hardening coating (by itself or with an activator and/or catalyst) and, when placed on a particulate, will increase the continuous critical resuspension velocity of the particulate when contacted by a stream of water. The aqueous tackifying agent may enhance the grain-to-grain contact between the individual particulates within the formation (be they proppant particulates, formation fines, or other particulates), helping bring about the consolidation of the particulates into a cohesive, flexible, and permeable mass. When used, the activator and/or catalyst may be a component of a treatment fluid comprising the aqueous tackifying agent, or may be introduced into the subterranean formation separately through the dynamic diversion tool (e.g., as a component of a treatment fluid) or by some other means (e.g., pumped into the annulus from the surface).
  • [0047]
    Examples of aqueous tackifying agents suitable for use in the present invention include, but are not limited to, acrylic acid polymers, acrylic acid ester polymers, acrylic acid derivative polymers, acrylic acid homopolymers, acrylic acid ester homopolymers (such as poly(methyl acrylate), poly(butyl acrylate), and poly(2-ethylhexyl acrylate)), acrylic acid ester co-polymers, methacrylic acid derivative polymers, methacrylic acid homopolymers, methacrylic acid ester homopolymers (such as poly(methyl methacrylate), poly(butyl methacrylate), and poly(2-ethylhexyl methacryate)), acrylamido-methyl-propane sulfonate polymers, acrylamido-methyl-propane sulfonate derivative polymers, acrylamido-methyl-propane sulfonate co-polymers, and acrylic acid/acrylamido-methyl-propane sulfonate co-polymers, and combinations thereof. The term “derivative” is defined herein to include any compound that is made from one of the listed compounds, for example, by replacing one atom in one of the listed compounds with another atom or group of atoms, ionizing one of the listed compounds, or creating a salt of one of the listed compounds. Methods of determining suitable aqueous tackifying agents and additional disclosure on aqueous tackifying agents can be found in U.S. patent application Ser. No. 10/864,061, filed Jun. 9, 2004, and U.S. patent application Ser. No. 10/864,618, filed Jun. 9, 2004, the relevant disclosures of which are hereby incorporated by reference.
  • [0048]
    Silyl-modified polyamide compounds suitable for use in the tackifying agents in the methods of the present invention may be described as substantially self-hardening compositions that are capable of at least partially adhering to particulates in the unhardened state, and that are further capable of self-hardening themselves to a substantially non-tacky state to which individual particulates such as formation fines will not adhere to, for example, in formation or proppant pack pore throats. Such silyl-modified polyamides may be based, for example, on the reaction product of a silating compound with a polyamide or a mixture of polyamides. The polyamide or mixture of polyamides may be one or more polyamide intermediate compounds obtained, for example, from the reaction of a polyacid (e.g., diacid or higher) with a polyamine (e.g., diamine or higher) to form a polyamide polymer with the elimination of water. Other suitable silyl-modified polyamides and methods of making such compounds are described in U.S. Pat. No. 6,439,309, the relevant disclosure of which is herein incorporated by reference.
  • [0049]
    Some suitable tackifying agents are described in U.S. Pat. No. 5,249,627 by Harms, et al., the relevant disclosure of which is incorporated by reference. Harms discloses aqueous tackifying agents that comprise at least one member selected from the group consisting of benzyl coco di-(hydroxyethyl) quaternary amine, p-T-amyl-phenol condensed with formaldehyde, and a copolymer comprising from about 80% to about 100% C1-30 alkylmethacrylate monomers and from about 0% to about 20% hydrophilic monomers. In some embodiments, the aqueous tackifying agent may comprise a copolymer that comprises from about 90% to about 99.5% 2-ethylhexylacrylate and from about 0.5% to about 10% acrylic acid. Suitable hydrophilic monomers may be any monomer that will provide polar oxygen-containing or nitrogen-containing groups. Suitable hydrophilic monomers include dialkyl amino alkyl (meth) acrylates and their quaternary addition and acid salts, acrylamide, N-(dialkyl amino alkyl) acrylamide, methacrylamides and their quaternary addition and acid salts, hydroxy alkyl (meth)acrylates, unsaturated carboxylic acids such as methacrylic acid or preferably acrylic acid, hydroxyethyl acrylate, acrylamide, and the like. These copolymers can be made by any suitable emulsion polymerization technique. Methods of producing these copolymers are disclosed, for example, in U.S. Pat. No. 4,670,501, the relevant disclosure of which is incorporated herein by reference.
  • [0050]
    C. Gelable Liquid Compositions
  • [0051]
    Gelable liquid compositions suitable for use in the methods of the present invention may comprise any gelable liquid composition capable of converting into a gelled substance capable of substantially plugging the permeability of the formation while allowing the formation to remain flexible. That is, the gelled substance should negatively impact the ability of the formation to produce desirable fluids such as hydrocarbons. As discussed above, the permeability of the formation may be restored through use of an afterflush fluid or by fracturing through the consolidated portion. As referred to herein, the term “flexible” refers to a state wherein the treated formation or material is relatively malleable and elastic and able to withstand substantial pressure cycling without substantial breakdown. Thus, the resultant gelled substance should be a semi-solid, immovable, gel-like substance, which, among other things, stabilizes the treated portion of the formation while allowing the formation to absorb the stresses created during pressure cycling. As a result, the gelled substance may aid in preventing breakdown of the formation both by stabilizing and by adding flexibility to the formation sands. Examples of suitable gelable liquid compositions include, but are not limited to, resin compositions that cure to form flexible gels, gelable aqueous silicate compositions, crosslinkable aqueous polymer compositions, and polymerizable organic monomer compositions.
  • [0052]
    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 proppant materials into hard, permeable masses. While the curable resin compositions used in accordance with the present invention may be similar to those previously used to consolidate sand and proppant into hard, permeable masses, they are distinct in that resins suitable for use with the present invention do not cure into hard, permeable masses; rather they cure into flexible, gelled substances. That is, suitable curable resin compositions form resilient gelled substances between the particulates of the treated portion of the unconsolidated formation and thus allow that portion of the formation to remain flexible and to resist breakdown. It is not necessary or desirable for the cured resin composition to solidify and harden to provide high consolidation strength to the treated portion of the formation. On the contrary, upon being cured, the curable resin compositions useful in accordance with this invention form semi-solid, immovable, gelled substances.
  • [0053]
    Generally, the 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 the curable resin compositions, the compositions form the semi-solid, immovable, gelled substances described above. Where the resin curing agent used may cause the organic resin compositions to form hard, brittle material rather than a desired gelled substance, the curable resin compositions may further comprise one or more “flexibilizer additives” (described in more detail below) to provide flexibility to the cured compositions.
  • [0054]
    Examples of curable resins that can 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-epichlorihydrin resins), polyester resins, urea-aldehyde resins, furan resins, urethane resins, and mixtures thereof. Of these, polyepoxide resins are preferred.
  • [0055]
    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 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 from about 3 to about 3,000 centipoises (“cP”) at 80° F. Among other things, the diluent 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 amount in the range of from about 5% to about 75% by weight of the curable resin.
  • [0056]
    Generally, any resin curing agent that may be used to cure an organic resin is suitable for use in the present invention. When the resin curing agent chosen is an amide or a polyamide, generally no flexibilizer additive will be required because, inter alia, such curing agents cause the curable resin composition to convert into a semi-solid, immovable, gelled substance. Other suitable resin curing agents (such as an amine, a polyamine, methylene dianiline, and other curing agents known in the art) will tend to cure into a hard, brittle material and will thus benefit from the addition of a flexibilizer additive. Generally, the resin curing agent used is included in the curable resin composition, whether a flexibilizer additive is included or not, 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 in the range of from about 20% to about 75% by weight of the curable resin.
  • [0057]
    As noted above, flexibilizer additives may be used, inter alia, to provide flexibility to the gelled substances formed from the curable resin compositions. The term “flexibilizer additive” is defined herein to include any substance that is capable of imparting properties of flexibility (e.g., malleability, elasticity) to the gelled substances formed from the curable resin compositions. Flexibilizer additives should be used where the resin curing agent chosen would cause the organic resin composition to cure into a hard and brittle material instead of desired gelled substances described herein. For example, flexibilizer additives may be used where the resin curing agent chosen is not an amide or polyamide. Examples of suitable flexibilizer 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 flexibilizer 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 flexibilizer additive may be included in the curable resin composition in an amount in the range of from about 20% to about 45% by weight of the curable resin.
  • [0058]
    In other embodiments, the gelable liquid compositions may comprise a gelable aqueous silicate composition. Generally, the gelable aqueous silicate compositions that are useful in accordance with the present invention generally comprise an aqueous alkali metal silicate solution and a temperature activated catalyst for gelling the aqueous alkali metal silicate solution.
  • [0059]
    The aqueous alkali metal silicate solution component of the gelable aqueous silicate compositions generally comprises an aqueous liquid and an alkali metal silicate. The aqueous liquid component of the aqueous alkali metal silicate solution generally may be fresh water, salt water (e.g., water containing one or more salts dissolved therein), brine (e.g., saturated salt water), seawater, or any other aqueous liquid that does not adversely react with the other components used in accordance with this invention or with the subterranean formation. Examples of suitable alkali metal silicates include, but are not limited to, one or more of sodium silicate, potassium silicate, lithium silicate, 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 Na2O-to-SiO2 weight ratio in the range of from about 1:2 to about 1:4. Most preferably, the sodium silicate used has a Na2O-to-SiO2 weight ratio in the range of about 1:3.2. Generally, the alkali metal silicate is present in the aqueous alkali metal silicate solution component in an amount in the range of from about 0.1% to about 10% by weight of the aqueous alkali metal silicate solution component.
  • [0060]
    The temperature-activated catalyst component of the gelable aqueous silicate compositions is used, inter alia, to convert the gelable aqueous silicate compositions into the desired semi-solid, immovable, gelled substance described above. Selection of a temperature activated catalyst is related, at least in part, to the temperature of the subterranean formation to which the gelable aqueous silicate composition will be introduced. The temperature activated catalysts which can be used in the gelable aqueous silicate compositions of the present invention include, but are not limited to, ammonium sulfate, which is most suitable in the range of from about 60° F. to about 240° F.; sodium acid pyrophosphate, which is most suitable in the range of from about 60° F. to about 240° F.; citric acid, which is most suitable in the range of from about 60° F. to about 120° F.; and ethyl acetate, which is most suitable in the range of from about 60° F. 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 gelable aqueous silicate composition. When used, the temperature activated catalyst may be a component of a treatment fluid comprising the gelable aqueous silicate composition, or may be introduced into the subterranean formation separately through the dynamic diversion tool (e.g., as a component of a treatment fluid) or by some other means (e.g., pumped into the annulus from the surface).
  • [0061]
    In other embodiments, the gelable liquid compositions may comprise crosslinkable aqueous polymer compositions. Generally, suitable crosslinkable aqueous polymer compositions may comprise an aqueous solvent, a crosslinkable polymer, and a crosslinking agent.
  • [0062]
    The aqueous solvent may be any aqueous solvent in which the crosslinkable composition and the crosslinking agent may be dissolved, mixed, suspended, or dispersed therein to facilitate gel formation. For example, the aqueous solvent used may be fresh water, salt water, brine, seawater, or any other aqueous liquid that does not adversely react with the other components used in accordance with this invention or with the subterranean formation.
  • [0063]
    Examples of crosslinkable polymers that can be used in the crosslinkable aqueous polymer compositions include, but are not limited to, carboxylate-containing polymers and acrylamide-containing polymers. Preferred acrylamide-containing polymers include polyacrylamide, partially hydrolyzed polyacrylamide, copolymers of acrylamide and acrylate, and carboxylate-containing terpolymers and tetrapolymers of acrylate. Additional examples of suitable crosslinkable polymers include hydratable polymers comprising polysaccharides and derivatives thereof and that contain one or more of the monosaccharide units galactose, mannose, glucoside, glucose, xylose, arabinose, fructose, glucuronic acid, or pyranosyl sulfate. Suitable natural hydratable polymers include, but are not limited to, guar gum, locust bean gum, tara, konjak, tamarind, starch, cellulose, karaya, xanthan, tragacanth, and carrageenan, and derivatives of all of the above. Suitable hydratable synthetic polymers and copolymers that may be used in the crosslinkable aqueous polymer compositions include, but are not limited to, polyacrylates, polymethacrylates, polyacrylamides, maleic anhydride, methylvinyl ether polymers, polyvinyl alcohols, and polyvinylpyrrolidone. The crosslinkable polymer used should be included in the crosslinkable aqueous polymer composition in an amount sufficient to form the desired gelled substance in the subterranean formation. In some embodiments of the present invention, the crosslinkable polymer is included in the crosslinkable aqueous polymer composition in an amount in the range of 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 aqueous polymer composition in an amount in the range of from about 1% to about 20% by weight of the aqueous solvent.
  • [0064]
    The crosslinkable aqueous polymer compositions of the present invention may further comprise a crosslinking agent for crosslinking the crosslinkable polymers to form the desired gelled substance. In some embodiments, the crosslinking agent may be a molecule or complex containing a reactive transition metal cation. A most preferred crosslinking agent comprises trivalent chromium cations complexed or bonded to anions, 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.
  • [0065]
    The crosslinking agent should be present in the crosslinkable aqueous polymer 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 aqueous polymer compositions of the present invention in an amount in the range of from 0.01% to about 5% by weight of the crosslinkable aqueous polymer composition. The exact type and amount of crosslinking agent or agents used depends upon the specific crosslinkable polymer to be crosslinked, formation temperature conditions, and other factors known to those individuals skilled in the art.
  • [0066]
    Optionally, the crosslinkable aqueous polymer compositions may further comprise a crosslinking delaying agent, such as a polysaccharide crosslinking delaying agents derived from guar, guar derivatives, or cellulose derivatives. The crosslinking delaying agent may be included in the crosslinkable aqueous polymer compositions, inter alia, to delay crosslinking of the crosslinkable aqueous polymer compositions until desired. One of ordinary skill in the art, with the benefit of this disclosure, will know the appropriate amount of the crosslinking delaying agent to include in the crosslinkable aqueous polymer compositions for a desired application.
  • [0067]
    In other embodiments, the gelled liquid compositions may comprise polymerizable organic monomer compositions. Generally, suitable polymerizable organic monomer compositions may comprise an aqueous-base fluid, a water-soluble polymerizable organic monomer, an oxygen scavenger, and a primary initiator.
  • [0068]
    The aqueous-base fluid component of the polymerizable organic monomer composition generally may be fresh water, salt water, brine, seawater, or any other aqueous liquid that does not adversely react with the other components used in accordance with this invention or with the subterranean formation.
  • [0069]
    A variety of monomers are suitable for use as the water-soluble polymerizable organic monomers in the present invention. Examples of suitable monomers include, but are not limited to, acrylic acid, methacrylic acid, acrylamide, methacrylamide, 2-methacrylamino-2-methylpropane sulfonic acid, 2-dimethylacrylamide, vinyl sulfonic acid, N,N-dimethylaminoethylmethacrylate, 2-triethylammoniumethylmethacrylate chloride, N,N-dimethyl-aminopropylmethacryl-amide, methacrylamidepropyltriethylammonium chloride, N-vinyl pyrrolidone, vinyl-phosphonic acid, and methacryloyloxyethyl trimethylammonium sulfate, and mixtures thereof. Preferably, the water-soluble polyrnerizable organic monomer should be self crosslinking. Examples of suitable monomers which are self crosslinking include, but are not limited to, hydroxyethylacrylate, hydroxymethylacrylate, hydroxyethylmethacrylate, N-hydroxymethylacrylamide, N-hydroxymethyl-methacrylamide, polyethylene glycol acrylate, polyethylene glycol methacrylate, polypropylene glycol acrylate, polypropylene glycol methacrylate, and mixtures thereof. Of these, hydroxyethylacrylate is preferred. An example of a particularly preferable monomer is hydroxyethylcellulose-vinyl phosphoric acid.
  • [0070]
    The water-soluble polymerizable organic monomer (or monomers where a mixture thereof is used) should be included in the polymerizable organic monomer composition in an amount sufficient to form the desired gelled substance after placement of the polymerizable organic monomer composition into the subterranean formation. In some embodiments of the present invention, the water-soluble polymerizable organic monomer(s) are included in the polymerizable organic monomer composition in an amount in the range of from about 1% to about 30% by weight of the aqueous-base fluid. In another embodiment of the present invention, the water-soluble polymerizable organic monomer(s) are included in the polymerizable organic monomer composition in an amount in the range of from about 1% to about 20% by weight of the aqueous-base fluid.
  • [0071]
    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 scavenger, such as stannous chloride, may be included in the polymerizable monomer composition. In order to improve the solubility of stannous chloride so that it may be readily combined with the polymerizable organic monomer composition on the fly, the stannous chloride may be pre-dissolved in a hydrochloric acid solution. For example, the stannous chloride may be dissolved in a 0.1% by weight aqueous hydrochloric acid solution in an amount of about 10% by weight of the resulting solution. The resulting stannous chloride-hydrochloric acid solution may be included in the polymerizable organic monomer composition in an amount in the range of from about 0.1% to about 10% by weight of the polymerizable organic monomer composition. Generally, the stannous chloride may be included in the polymerizable organic monomer composition of the present invention in an amount in the range of from about 0.005% to about 0.1% by weight of the polymerizable organic monomer composition.
  • [0072]
    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 aqueous solution may be used as the primary initiator. The free radicals act, inter alia, to initiate polymerization of the water-soluble polymerizable organic monomer(s) present in the polymerizable organic monomer composition. Compounds suitable for use as the primary initiator include, but are not limited to, alkali metal persulfates; peroxides; oxidation-reduction systems employing reducing agents, such as sulfites in combination with oxidizers; and azo polymerization initiators. Preferred azo polymerization initiators include 2,2′-azobis(2-imidazole-2-hydroxyethyl) propane, 2,2′-azobis(2-aminopropane), 4,4′-azobis(4-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 water-soluble polymerizable organic monomer(s).
  • [0073]
    Optionally, the polymerizable organic monomer compositions further may comprise a secondary initiator. A secondary initiator may be used, for example, where the immature aqueous gel is placed into a subterranean formation that is relatively cool as compared to the surface mixing, such as when placed below the mud line in offshore operations. The secondary initiator may be any suitable water-soluble compound or compounds that 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 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 water-soluble polymerizable organic monomer(s).
  • [0074]
    Optionally, the polymerizable organic monomer compositions of the present invention further may comprise a crosslinking agent for crosslinking the polymerizable organic monomer compositions in the desired gelled substance. In some embodiments, the crosslinking agent is a molecule or complex containing a reactive transition metal cation. A most preferred crosslinking agent comprises trivalent chromium cations complexed or bonded to anions, 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 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.
  • [0075]
    Therefore, the present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present 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. While numerous changes may be made by those skilled in the art, such changes are encompassed within the spirit of this invention as defined by the appended claims. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as 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, every range of values (e.g., “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood as referring to the power set (the set of all subsets) of the respective range of values. The terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee.
Citas de patentes
Patente citada Fecha de presentación Fecha de publicación Solicitante Título
US2869642 *14 Sep 195420 Ene 1959Texas CoMethod of treating subsurface formations
US3297086 *30 Mar 196210 Ene 1967Exxon Production Research CoSand consolidation method
US3297090 *24 Abr 196410 Ene 1967Shell Oil CoAcidizing oil formations
US3302719 *25 Ene 19657 Feb 1967Union Oil CoMethod for treating subterranean formations
US3362477 *13 Nov 19649 Ene 1968Chevron ResMethod and apparatus for injecting fluids into earth formations penetrated by a well
US3364995 *14 Feb 196623 Ene 1968Dow Chemical CoHydraulic fracturing fluid-bearing earth formations
US3366178 *10 Sep 196530 Ene 1968Halliburton CoMethod of fracturing and propping a subterranean formation
US3489222 *26 Dic 196813 Ene 1970Chevron ResMethod of consolidating earth formations without removing tubing from well
US3492147 *22 Oct 196427 Ene 1970Halliburton CoMethod of coating particulate solids with an infusible resin
US3565176 *8 Sep 196923 Feb 1971Wittenwyler Clifford VConsolidation of earth formation using epoxy-modified resins
US3708013 *3 May 19712 Ene 1973Mobil Oil CorpMethod and apparatus for obtaining an improved gravel pack
US3709298 *20 May 19719 Ene 1973Shell Oil CoSand pack-aided formation sand consolidation
US3709641 *3 Ago 19709 Ene 1973Union Oil CoApparatus for preparing and extruding a gelatinous material
US3784585 *21 Oct 19718 Ene 1974American Cyanamid CoWater-degradable resins containing recurring,contiguous,polymerized glycolide units and process for preparing same
US3861467 *28 Dic 197321 Ene 1975Texaco IncPermeable cementing method
US3863709 *20 Dic 19734 Feb 1975Mobil Oil CorpMethod of recovering geothermal energy
US3933205 *27 Ene 197520 Ene 1976Othar Meade KielHydraulic fracturing process using reverse flow
US4000781 *13 Nov 19754 Ene 1977Shell Oil CompanyWell treating process for consolidating particles with aqueous emulsions of epoxy resin components
US4008763 *20 May 197622 Feb 1977Atlantic Richfield CompanyWell treatment method
US4009757 *3 Feb 19751 Mar 1977Vann Roy RandellSand consolidation method
US4068718 *26 Oct 197617 Ene 1978Exxon Production Research CompanyHydraulic fracturing method using sintered bauxite propping agent
US4070865 *10 Mar 197631 Ene 1978Halliburton CompanyMethod of consolidating porous formations using vinyl polymer sealer with divinylbenzene crosslinker
US4074760 *1 Nov 197621 Feb 1978The Dow Chemical CompanyMethod for forming a consolidated gravel pack
US4245702 *7 May 197920 Ene 1981Shell Internationale Research Maatschappij B.V.Method for forming channels of high fluid conductivity in hard acid-soluble formations
US4247430 *11 Abr 197927 Ene 1981The Dow Chemical CompanyAqueous based slurry and method of forming a consolidated gravel pack
US4374739 *4 Feb 198022 Feb 1983Halliburton CompanyOil well treating method and composition
US4428427 *3 Dic 198131 Ene 1984Getty Oil CompanyConsolidatable gravel pack method
US4493875 *9 Dic 198315 Ene 1985Minnesota Mining And Manufacturing CompanyProppant for well fractures and method of making same
US4494605 *11 Dic 198122 Ene 1985Texaco Inc.Sand control employing halogenated, oil soluble hydrocarbons
US4498995 *1 Jul 198312 Feb 1985Judith GockelLost circulation drilling fluid
US4501328 *14 Mar 198326 Feb 1985Mobil Oil CorporationMethod of consolidation of oil bearing sands
US4563292 *2 Ago 19847 Ene 1986Halliburton CompanyMethods for stabilizing fines contained in subterranean formations
US4564459 *13 Abr 198414 Ene 1986Baker Oil Tools, Inc.Proppant charge and method
US4572803 *30 Jun 198225 Feb 1986Asahi Dow LimitedOrganic rare-earth salt phosphor
US4716964 *10 Dic 19865 Ene 1988Exxon Production Research CompanyUse of degradable ball sealers to seal casing perforations in well treatment fluid diversion
US4796701 *30 Jul 198710 Ene 1989Dowell Schlumberger IncorporatedPyrolytic carbon coating of media improves gravel packing and fracturing capabilities
US4797262 *3 Jun 198710 Ene 1989Shell Oil CompanyDownflow fluidized catalytic cracking system
US4800960 *18 Dic 198731 Ene 1989Texaco Inc.Consolidatable gravel pack method
US4892147 *28 Dic 19879 Ene 1990Mobil Oil CorporationHydraulic fracturing utilizing a refractory proppant
US4895207 *19 Dic 198823 Ene 1990Texaco, Inc.Method and fluid for placing resin coated gravel or sand in a producing oil well
US4898750 *5 Dic 19886 Feb 1990Texaco Inc.Processes for forming and using particles coated with a resin which is resistant to high temperature and high pH aqueous environments
US4903770 *30 May 198927 Feb 1990Texaco Inc.Sand consolidation methods
US4984635 *16 Nov 198915 Ene 1991Mobil Oil CorporationThermal barriers for enhanced oil recovery
US4986353 *14 Sep 198822 Ene 1991Conoco Inc.Placement process for oil field chemicals
US4986354 *14 Sep 198822 Ene 1991Conoco Inc.Composition and placement process for oil field chemicals
US4986355 *18 May 198922 Ene 1991Conoco Inc.Process for the preparation of fluid loss additive and gel breaker
US5082056 *16 Oct 199021 Ene 1992Marathon Oil CompanyIn situ reversible crosslinked polymer gel used in hydrocarbon recovery applications
US5101900 *27 Dic 19907 Abr 1992Oryx Energy CompanySand control in wells with gas generator and resin
US5178218 *19 Jun 199112 Ene 1993Oryx Energy CompanyMethod of sand consolidation with resin
US5182051 *7 Mar 199126 Ene 1993Protechnics International, Inc.Raioactive tracing with particles
US5278203 *5 Nov 199211 Ene 1994Halliburton CompanyMethod of preparing and improved liquid gelling agent concentrate and suspendable gelling agent
US5285849 *6 Jul 199215 Feb 1994Texaco Inc.Formation treating methods
US5377753 *24 Jun 19933 Ene 1995Texaco Inc.Method and apparatus to improve the displacement of drilling fluid by cement slurries during primary and remedial cementing operations, to improve cement bond logs and to reduce or eliminate gas migration problems
US5377756 *28 Oct 19933 Ene 1995Mobil Oil CorporationMethod for producing low permeability reservoirs using a single well
US5379841 *12 Abr 199310 Ene 1995Hoechst AktiengesellschaftMethod for reducing or completely stopping the influx of water in boreholes for the extraction of oil and/or hydrocarbon gas
US5381864 *12 Nov 199317 Ene 1995Halliburton CompanyWell treating methods using particulate blends
US5382371 *6 Nov 199217 Ene 1995Phillips Petroleum CompanyPolymers useful in the recovery and processing of natural resources
US5386874 *8 Nov 19937 Feb 1995Halliburton CompanyPerphosphate viscosity breakers in well fracture fluids
US5388648 *8 Oct 199314 Feb 1995Baker Hughes IncorporatedMethod and apparatus for sealing the juncture between a vertical well and one or more horizontal wells using deformable sealing means
US5390741 *21 Dic 199321 Feb 1995Halliburton CompanyRemedial treatment methods for coal bed methane wells
US5393810 *30 Dic 199328 Feb 1995Halliburton CompanyMethod and composition for breaking crosslinked gels
US5443123 *14 Mar 199422 Ago 1995Halliburton CompanyMethod of particulate consolidation
US5484881 *23 Ago 199316 Ene 1996Cargill, Inc.Melt-stable amorphous lactide polymer film and process for manufacturing thereof
US5492177 *1 Dic 199420 Feb 1996Mobil Oil CorporationMethod for consolidating a subterranean formation
US5494178 *25 Jul 199427 Feb 1996Alu Inc.Display and decorative fixture apparatus
US5591700 *22 Dic 19947 Ene 1997Halliburton CompanyFracturing fluid with encapsulated breaker
US5594095 *27 Jul 199414 Ene 1997Cargill, IncorporatedViscosity-modified lactide polymer composition and process for manufacture thereof
US5595245 *4 Ago 199521 Ene 1997Scott, Iii; George L.Systems of injecting phenolic resin activator during subsurface fracture stimulation for enhanced oil recovery
US5597783 *4 May 199528 Ene 1997Institut Francais Du PetroleDrilling processes and fluid used in well drilling applications
US5597784 *6 Jun 199528 Ene 1997Santrol, Inc.Composite and reinforced coatings on proppants and particles
US5604184 *10 Abr 199518 Feb 1997Texaco, Inc.Chemically inert resin coated proppant system for control of proppant flowback in hydraulically fractured wells
US5604186 *15 Feb 199518 Feb 1997Halliburton CompanyEncapsulated enzyme breaker and method for use in treating subterranean formations
US5712314 *9 Ago 199627 Ene 1998Texaco Inc.Formulation for creating a pliable resin plug
US5720347 *11 Ene 199624 Feb 1998Institut Francais Du PetroleProcess and water-base fluid utilizing hydrophobically modified guars as filtrate reducers
US5864003 *23 Jul 199626 Ene 1999Georgia-Pacific Resins, Inc.Thermosetting phenolic resin composition
US5865936 *28 Mar 19972 Feb 1999National Starch And Chemical Investment Holding CorporationRapid curing structural acrylic adhesive
US6012524 *14 Abr 199811 Ene 2000Halliburton Energy Services, Inc.Remedial well bore sealing methods and compositions
US6016870 *11 Jun 199825 Ene 2000Halliburton Energy Services, Inc.Compositions and methods for consolidating unconsolidated subterranean zones
US6169058 *5 Jun 19972 Ene 2001Bj Services CompanyCompositions and methods for hydraulic fracturing
US6172011 *8 Mar 19969 Ene 2001Schlumberger Technolgy CorporationControl of particulate flowback in subterranean wells
US6172077 *22 Abr 19989 Ene 2001Merck Sharp & Dohme Ltd.Spiro-azacyclic derivatives and their use as therapeutic agents
US6176315 *4 Dic 199823 Ene 2001Halliburton Energy Services, Inc.Preventing flow through subterranean zones
US6177484 *3 Nov 199823 Ene 2001Texaco Inc.Combination catalyst/coupling agent for furan resin
US6503870 *30 Ago 20017 Ene 2003Halliburton Energy Services, Inc.Sealing subterranean zones
US6508305 *14 Sep 200021 Ene 2003Bj Services CompanyCompositions and methods for cementing using elastic particles
US6510896 *4 May 200128 Ene 2003Weatherford/Lamb, Inc.Apparatus and methods for utilizing expandable sand screen in wellbores
US6677426 *14 May 200213 Ene 2004Resolution Performance Products LlcModified epoxy resin composition, production process for the same and solvent-free coating comprising the same
US6681856 *16 May 200327 Ene 2004Halliburton Energy Services, Inc.Methods of cementing in subterranean zones penetrated by well bores using biodegradable dispersants
US6837309 *8 Ago 20024 Ene 2005Schlumberger Technology CorporationMethods and fluid compositions designed to cause tip screenouts
US7156194 *26 Ago 20032 Ene 2007Halliburton Energy Services, Inc.Methods of drilling and consolidating subterranean formation particulate
US20010050172 *12 Feb 200113 Dic 2001Tolman Randy C.Method and apparatus for stimulation of multiple formation intervals
US20030013871 *2 Feb 200116 Ene 2003Mallon Charles B.Method of preparing modified cellulose ether
US20030019627 *17 Ene 200230 Ene 2003Qi QuCompositions containing aqueous viscosifying surfactants and methods for applying such compositions in subterranean formations
US20040000402 *30 Sep 20021 Ene 2004Nguyen Philip D.Methods of consolidating proppant and controlling fines in wells
US20040014607 *16 Jul 200222 Ene 2004Sinclair A. RichardDownhole chemical delivery system for oil and gas wells
US20040014608 *19 Jul 200222 Ene 2004Nguyen Philip D.Methods of preventing the flow-back of particulates deposited in subterranean formations
US20050000694 *2 Jul 20036 Ene 2005Dalrymple Eldon D.Methods of reducing water permeability for acidizing a subterranean formation
US20050000731 *3 Jul 20036 Ene 2005Nguyen Philip D.Method and apparatus for treating a productive zone while drilling
US20050006093 *7 Jul 200313 Ene 2005Nguyen Philip D.Methods and compositions for enhancing consolidation strength of proppant in subterranean fractures
US20050006095 *8 Jul 200313 Ene 2005Donald JustusReduced-density proppants and methods of using reduced-density proppants to enhance their transport in well bores and fractures
US20050006096 *9 Jul 200313 Ene 2005Nguyen Philip D.Methods of consolidating subterranean zones and compositions therefor
US20070007010 *11 Jul 200511 Ene 2007Halliburton Energy Services, Inc.Methods and compositions for controlling formation fines and reducing proppant flow-back
US20070012445 *15 Jul 200518 Ene 2007Halliburton Energy Services, Inc.Methods for controlling water and sand production in subterranean wells
Otras citas
Referencia
1 *"proppant" Schlumberger Oilfield Glossary, retrieved 03/14/13 from http://www.glossary.oilfield.slb.com/en/Terms.aspx?LookIn=term%20name&filter=proppant
Citada por
Patente citante Fecha de presentación Fecha de publicación Solicitante Título
US7398825 *21 Nov 200515 Jul 2008Halliburton Energy Services, Inc.Methods of controlling sand and water production in subterranean zones
US76736869 Mar 2010Halliburton Energy Services, Inc.Method of stabilizing unconsolidated formation for sand control
US7690431 *14 Nov 20076 Abr 2010Halliburton Energy Services, Inc.Methods for controlling migration of particulates in a subterranean formation
US771253126 Jul 200711 May 2010Halliburton Energy Services, Inc.Methods for controlling particulate migration
US773095019 Ene 20078 Jun 2010Halliburton Energy Services, Inc.Methods for treating intervals of a subterranean formation having variable permeability
US776232927 Ene 200927 Jul 2010Halliburton Energy Services, Inc.Methods for servicing well bores with hardenable resin compositions
US776609923 Oct 20083 Ago 2010Halliburton Energy Services, Inc.Methods of drilling and consolidating subterranean formation particulates
US781919210 Feb 200626 Oct 2010Halliburton Energy Services, Inc.Consolidating agent emulsions and associated methods
US792659112 Ene 200919 Abr 2011Halliburton Energy Services, Inc.Aqueous-based emulsified consolidating agents suitable for use in drill-in applications
US793455715 Feb 20073 May 2011Halliburton Energy Services, Inc.Methods of completing wells for controlling water and particulate production
US796333021 Jun 2011Halliburton Energy Services, Inc.Resin compositions and methods of using resin compositions to control proppant flow-back
US799891016 Ago 2011Halliburton Energy Services, Inc.Treatment fluids comprising relative permeability modifiers and methods of use
US801756113 Sep 2011Halliburton Energy Services, Inc.Resin compositions and methods of using such resin compositions in subterranean applications
US809163810 Ene 2012Halliburton Energy Services, Inc.Methods useful for controlling fluid loss in subterranean formations
US81670451 May 2012Halliburton Energy Services, Inc.Methods and compositions for stabilizing formation fines and sand
US818170322 May 2012Halliburton Energy Services, Inc.Method useful for controlling fluid loss in subterranean formations
US8196655 *12 Jun 2012Halliburton Energy Services, Inc.Selective placement of conformance treatments in multi-zone well completions
US8215393 *6 Oct 200910 Jul 2012Schlumberger Technology CorporationMethod for treating well bore within a subterranean formation
US82511419 Ago 200628 Ago 2012Halliburton Energy Services, Inc.Methods useful for controlling fluid loss during sand control operations
US827244025 Sep 2012Halliburton Energy Services, Inc.Methods for placement of sealant in subterranean intervals
US8360145 *6 Abr 201229 Ene 2013Halliburton Energy Services, Inc.Selective placement of conformance treatments in multi-zone well completions
US842057616 Abr 2013Halliburton Energy Services, Inc.Hydrophobically and cationically modified relative permeability modifiers and associated methods
US844388530 Ago 200721 May 2013Halliburton Energy Services, Inc.Consolidating agent emulsions and associated methods
US845935210 Dic 201211 Jun 2013Halliburton Energy Services, Inc.Selective placement of conformance treatments in multi-zone well completions
US8479819 *31 Dic 20089 Jul 2013Schlumberger Technology CorporationMethod of consolidating a fracture in a formation
US861332015 Feb 200824 Dic 2013Halliburton Energy Services, Inc.Compositions and applications of resins in treating subterranean formations
US86318698 Abr 200521 Ene 2014Leopoldo SierraMethods useful for controlling fluid loss in subterranean treatments
US868987224 Jul 20078 Abr 2014Halliburton Energy Services, Inc.Methods and compositions for controlling formation fines and reducing proppant flow-back
US8893790 *23 May 201225 Nov 2014Halliburton Energy Services, Inc.Biomimetic adhesive compositions comprising a phenolic polymer and methods for use thereof
US896253531 Jul 200924 Feb 2015Halliburton Energy Services, Inc.Methods of diverting chelating agents in subterranean treatments
US20050199396 *8 Abr 200515 Sep 2005Leopoldo SierraMethods useful for controlling fluid loss in subterranean treatments
US20060118470 *21 Nov 20058 Jun 2006Jkv Filtration Systems GmbhLeakage indicator for a filter element of a filter press
US20060234874 *20 Jun 200619 Oct 2006Halliburton Energy Services, Inc.Methods and compositions for reducing the production of water and stimulating hydrocarbon production from a subterranean formation
US20060240994 *20 Jun 200626 Oct 2006Halliburton Energy Services, Inc.Methods and compositions for reducing the production of water and stimulating hydrocarbon production from a subterranean formation
US20060266522 *9 Ago 200630 Nov 2006Halliburton Energy Services, Inc.Methods useful for controlling fluid loss during sand control operations
US20060283592 *12 Jul 200621 Dic 2006Halliburton Energy Services, Inc.Method useful for controlling fluid loss in subterranean formations
US20090120639 *14 Nov 200714 May 2009Halliburton Energy Services, Inc.Methods for controlling migration of particulates in a subterranean formation
US20090120642 *14 Nov 200714 May 2009Halliburton Energy Services, Inc.Methods to enhance gas production following a relative-permeability-modifier treatment
US20090253594 *4 Abr 20088 Oct 2009Halliburton Energy Services, Inc.Methods for placement of sealant in subterranean intervals
US20100101773 *6 Ene 201029 Abr 2010Nguyen Philip DMethods of Cleaning Sand Control Screens and Gravel Packs
US20100116498 *17 Dic 200913 May 2010Dalrymple Eldon DMethods for Placement of Sealant in Subterranean Intervals
US20110034351 *10 Ago 200910 Feb 2011Eoff Larry SHydrophobically and Cationically Modified Relative Permeability Modifiers and Associated Methods
US20110048707 *31 Ago 20093 Mar 2011Halliburton Energy Services, Inc.Selective placement of conformance treatments in multi-zone well completions
US20110079389 *7 Abr 2011Mackay Bruce AMethod for treating well bore within a subterranean formation
US20110120711 *31 Dic 200826 May 2011Simon JamesA method of consolidating a fracture in a formation
US20110146987 *21 Dic 200923 Jun 2011Don WilliamsonChemical diversion technique
US20130312961 *23 May 201228 Nov 2013Halliburton Energy Services, Inc.Biomimetic Adhesive Compositions Comprising a Phenolic Polymer and Methods for Use Thereof
CN103773342A *12 Dic 20137 May 2014中国石油化工股份有限公司Large-pore composite plugging system and preparation method thereof
CN103865503A *10 Mar 201418 Jun 2014东北石油大学Novel high-temperature resistant inorganic particle-gel compound double-liquid blocking agent and blocking method thereof
WO2015038123A1 *12 Sep 201319 Mar 2015Halliburton Energy Services, Inc.Low-toxicity, polymerizable aqueous consolidation compositions for use in subterranean formation consolidation treatments
Clasificaciones
Clasificación de EE.UU.166/287, 166/290, 166/292, 166/295
Clasificación internacionalE21B33/13
Clasificación cooperativaC09K8/56
Clasificación europeaC09K8/56
Eventos legales
FechaCódigoEventoDescripción
7 Feb 2006ASAssignment
Owner name: HALLIBURTON ENERGY SERVICES, INC., TEXAS
Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNORS:STEGENT, NEIL A.;NGUYEN, PHILIP D.;HALLIBURTON, KEVIN W.;AND OTHERS;REEL/FRAME:017525/0121;SIGNING DATES FROM 20051214 TO 20060118