WO2008099154A1 - Methods of completing wells for controlling water and particulate production - Google Patents
Methods of completing wells for controlling water and particulate production Download PDFInfo
- Publication number
- WO2008099154A1 WO2008099154A1 PCT/GB2008/000476 GB2008000476W WO2008099154A1 WO 2008099154 A1 WO2008099154 A1 WO 2008099154A1 GB 2008000476 W GB2008000476 W GB 2008000476W WO 2008099154 A1 WO2008099154 A1 WO 2008099154A1
- Authority
- WO
- WIPO (PCT)
- Prior art keywords
- resin
- fluid
- hydrocarbon
- composition
- water
- Prior art date
Links
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/32—Preventing gas- or water-coning phenomena, i.e. the formation of a conical column of gas or water around wells
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
- C09K8/502—Oil-based compositions
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
- C09K8/504—Compositions based on water or polar solvents
- C09K8/506—Compositions based on water or polar solvents containing organic compounds
- C09K8/508—Compositions based on water or polar solvents containing organic compounds macromolecular compounds
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
- C09K8/504—Compositions based on water or polar solvents
- C09K8/506—Compositions based on water or polar solvents containing organic compounds
- C09K8/508—Compositions based on water or polar solvents containing organic compounds macromolecular compounds
- C09K8/512—Compositions based on water or polar solvents containing organic compounds macromolecular compounds containing cross-linking agents
Definitions
- the present disclosure relates to methods of completing wells in subterranean formations, such as in unconsolidated subterranean formations. More particularly, the present disclosure relates to methods of completing wells in unconsolidated subterranean formations for controlling water and particulate production.
- Well completions may involve a number of stages, including the installation of additional equipment into the well and the performance of procedures to prepare the well for production.
- well completions may include perforating casing that is cemented into the well bore so that fluids can flow, for example, from the formation and into the well bore.
- Completing the well may also include the installation of production tubing inside the well bore through which fluids may be produced from the bottom of the well bore to the surface.
- Well completions also may involve a number of other procedures performed in the well and to the surrounding formation, for example, to address issues related to undesired particulate and water production.
- unconsolidated subterranean formation refers to a subterranean formation that contains loose particulates and/or particulates bonded with insufficient bond strength to withstand forces created by the production (or injection) of fluids through the formation.
- particulates present in the unconsolidated subterranean formation may include, for example, sand, crushed gravel, crushed proppant, fines, and the like. When the well is placed into production, these particulates may migrate out of the formation with the fluids produced by the wells.
- the presence of such particulates in produced fluids may be undesirable in that the particulates may, for example, abrade downhole and surface equipment (e.g., pumps, flow lines, etc.) and/or reduce the production of desired fluids from the well.
- the migrating particulates may clog flow paths, such as formation pores, perforations, and the like, thereby reducing production.
- a number of well completion techniques have been developed to control particulate production in unconsolidated subterranean formations.
- One technique of controlling particulate production includes placing a filtration bed containing gravel (e.g., a "gravel pack") near the well bore to provide a physical barrier to the migration of particulates with the production (or injection) of fluids.
- a filtration bed containing gravel e.g., a "gravel pack”
- Such "gravel-packing operations” involve the pumping and placement of a quantity of gravel into the unconsolidated 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 consolidating fluid e.g., resins, tackiflers, etc.
- the consolidating fluid should enhance the grain-to-grain (or grain-to-formation) contact between particulates in the treated portion of the subterranean formation so that the particulates are stabilized, locked in place, or at least partially immobilized such that they are resistant to flowing with produced or injected fluids.
- the undesired production of water may constitute a major expense in the production of hydrocarbons from subterranean formations, for example, due to the energy expended in producing, separating, and disposing of the water.
- the water when produced through unconsolidated subterranean formations, the water may also have an undesirable effect on the migration of formation sands. While wells are typically completed in hydrocarbon-producing formations, a water-bearing zone may occasionally be adjacent to the hydrocarbon-producing formation. In some instances, the water may be communicated with the hydrocarbon-producing formation by way of fractures and/or high-permeability streaks.
- undesired water production may be caused by a variety of other occurrences, including, for example, water coning, water cresting, bottom water, channeling at the well bore (e.g., channels behind casing formed by imperfect bonding between cement and casing), and the like.
- well completions may include procedures to address issues that may be encountered with the undesired production of water.
- One attempt to address these issues has been to inject sealing compositions into the formation to form an artificial barrier between the water-bearing zone and the hydrocarbon-producing formation.
- a gelable fluid may be introduced into the formation in a flowable state and thereafter form a gel in the formation that plugs off formation flow paths to eliminate, or at least reduce, the flow of water.
- Crosslinkable gels have also been used in a similar manner.
- certain polymers commonly referred to as "relative-permeability modifiers”
- the use of relative- permeability modifiers may be desirable, for example, where hydrocarbons will be produced from the treated portion of the formation.
- the present disclosure relates to methods of completing wells in subterranean formations, such as in unconsolidated subterranean formations. More particularly, the present disclosure relates to methods of completing wells in unconsolidated subterranean formations for controlling water and particulate production.
- An exemplary embodiment of the present invention provides a method of completing a well.
- the method comprises forming an artificial barrier to water flow, wherein the artificial barrier is located at or above a hydrocarbon-water interface between a waterbearing formation zone and a hydrocarbon-bearing formation zone.
- the method further comprises consolidating a portion of the hydrocarbon-bearing formation zone, wherein the artificial barrier is located between the consolidated portion of the hydrocarbon-bearing formation zone and the water-bearing formation zone.
- Another exemplary embodiment of the present invention provides a method of completing a well for controlling water and particulate production.
- the method comprises identifying a hydrocarbon-water interface between a hydrocarbon-bearing formation zone and a water-bearing formation zone.
- the method further comprises perforating a first interval of a casing, and introducing a sealing composition into one or more subterranean formations surrounding the first interval to form an artificial barrier to water flow.
- the artificial barrier is located either at or above the hydrocarbon-water interface.
- the method further comprises perforating a second interval of the casing, wherein the second interval is located above the first interval.
- the method further comprises introducing a consolidating fluid into one or more subterranean formations surrounding the second interval so as to consolidate at least a portion of the one or more subterranean formations.
- Another exemplary embodiment of the present invention provides a method of completing a well for controlling water and particulate production.
- the method comprises positioning a jetting tool at a first location in a well bore and perforating a first interval of casing at the first location.
- the perforating of the first interval comprises using the jetting tool to form one or more perforations that penetrate through the casing.
- the method further comprises introducing a sealing composition through the jetting tool and into one or more subterranean formations surrounding the first interval to form an artificial barrier to water flow.
- the method further comprises positioning the jetting tool in the well bore at a second location above the first location, and perforating a second interval of casing at the second location in the well bore.
- the perforating of the second interval comprises using the jetting tool to form one or more perforations that penetrate through the casing.
- the method further comprises introducing a consolidating fluid through the jetting tool and into one or more subterranean formations surrounding the second interval so as to consolidate at least a portion of the one or more subterranean formations.
- Figure 1 is a cross-sectional, side view of a subterranean formation that is penetrated by a cased well bore, in accordance with exemplary embodiments of the present invention
- Figure 2 is a cross-sectional, side view of the subterranean formation of Figure 1 after treatment with a sealing composition to form an artificial barrier, in accordance with exemplar ⁇ ' embodiments of the present invention
- Figure 3 is a cross-sectional, top view of the treated subterranean formation of Figure 2 taken along line 3-3, in accordance with exemplary embodiments of the present invention
- Figure 4 is a cross-sectional, side view of the treated subterranean formation of Figure 2 after additional treatment with a consolidating fluid, in accordance with exemplary embodiments of the present invention
- Figure 5 is a cross-sectional, top view of the treated subterranean formation of Figure 4 taken along line 5-5, in accordance with exemplary embodiments of the present invention.
- Figure 6 is a cross-sectional, top view of the treated subterranean formation of Figure 4 taken along line 5-5, after an additional fracturing treatment, in accordance with exemplary embodiments of the present invention.
- the present disclosure relates to methods of completing wells in subterranean formations, such as in unconsolidated subterranean formations. More particularly, the present disclosure relates to methods of completing wells in unconsolidated subterranean formations for controlling water and particulate production.
- a well bore 10 is shown that penetrates a hydrocarbon-bearing zone 12 and a water-bearing zone 14. Even though Figure 1 depicts the well bore 10 as a vertical well bore, the methods of the present invention may be suitable for use in deviated or otherwise formed portions of wells. Moreover, as those of ordinary skill in the art will appreciate, exemplary embodiments of the present invention are applicable for the treatment of both production and injection wells.
- well bore 10 is lined with casing 16 that is cemented to the subterranean formation by cement 18.
- casing 16 that is cemented to the subterranean formation by cement 18.
- At least a portion of the hydrocarbon-bearing zone 12 may be an unconsolidated formation that contains loose particulates and/or particulates bonded with insufficient bond strength to withstand forces created by the production of fluids through the formation. Accordingly, when the well is completed and the hydrocarbon-bearing zone 12 is placed into production, these particulates may undesirably migrate out of the formation with the fluids produced by the well. Moreover, as illustrated, the hydrocarbon-bearing zone 12 may be adjacent to a water-bearing zone 14.
- exemplary embodiments of the present invention generally address these issues of particulate and water production through successive treatments of different formation intervals with a sealing composition to form an artificial barrier that prevents water flow and with a consolidating fluid to control particulate production.
- completion of the well may include identifying the location of the hydrocarbon- water interface 20, perforating a first interval 22 of the well bore 10, and introducing a sealing composition into the portion of the subterranean formation surrounding the first interval 22 so that an artificial barrier 24 to water flow is formed.
- identification of the hydrocarbon-water interface 20 may include identifying the location of the water-bearing zone 14 so that the location of the hydrocarbon-water interface 20 may be identified.
- the location of the waterbearing zone 14 and the location of the hydrocarbon- water interface 20 may be identified using any suitable technique, including, for example, logging after a well bore is drilled or logging while drilling.
- Figure 2 depicts the first interval 22 as being above the hydrocarbon- water interface 20
- the first interval 22 may be at any suitable location for the formation of the artificial barrier 24 to water flow.
- the artificial barrier 24 may be formed at the hydrocarbon- water interface.
- the bottom of the artificial barrier 24 may be located about five feet, about ten feet or even greater above the hydrocarbon-water interface 20, for example, to effectively control water coning or cresting.
- placing the top of the artificial barrier 24 above the hydrocarbon-water interface 20 should prevent the flow of water from the water-bearing zone 14 to the hydrocarbon-bearing zone 12.
- the artificial barrier 24 may overlap the hydrocarbon water interface 20. Accordingly, the first interval 22 may be located at a distance above (e.g., within about five feet, ten feet or greater) the hydrocarbon- water interface 20. Moreover, the first interval 22 may have any suitable length (L) for the desired treatment. By way of example, the first interval 22 may have a length (L) in the range of from about 1 foot to about 50 feet.
- exemplary embodiments of the present invention may include perforating a first interval 22 of the well bore 10.
- perforations 26 may be formed that penetrate through the casing 16 and the cement sheath 18 and into the formation.
- the portion of the hydrocarbon-bearing zone 12 surrounding the first interval 22 may then be treated through the perforations 26 with a sealing composition to form an artificial barrier 24 to prevent, or at least substantially reduce, the migration of water from the water-bearing zone 14 to the hydrocarbon-bearing zone 12.
- Jetting tool 28 may be any suitable assembly for use in subterranean operations through which a fluid may be jetted at high pressures.
- the jetting tool 28 should be configured to jet a fluid against the casing 16 and the cement sheath 18 such that perforations 26 may be formed.
- jetting tool 28 may contain ports 30 for discharging a fluid from the jetting tool 28.
- the ports 30 form discharge jets as a result of a high pressure fluid forced out of relatively small ports.
- fluid jet forming nozzles ma ⁇ ' be connected within the ports 30.
- suitable jetting tools are described in U.S. Pat. Nos. 5,765,642 and 5,499,678, the disclosures of which are incorporated herein by reference.
- the jetting tool 28 may be positioned in the well bore 10 adjacent the portion of the well bore 10 to be perforated, such as the first interval 22.
- the jetting tool 28 may be coupled to a work string 32 (e.g., piping, coiled tubing, etc.) and lowered into the well bore 10 to the desired position.
- a work string 32 e.g., piping, coiled tubing, etc.
- a fluid may be pumped down through the work string 32, into the jetting tool 28, out through the ports 30, and against the interior surface of the casing 16 causing perforations 26 to be formed through the casing 16 and the cement sheath 18.
- abrasives e.g., sand
- a sealing composition may be introduced into the portion of the subterranean formation surrounding the first interval 22 so that an artificial barrier 24 to water flow is formed.
- the sealing composition may be any suitable composition suitable for forming an artificial barrier (such as artificial barrier 24) to water flow in the treated portion of the subterranean formation such that the flow of water therethrough is eliminated or at least substantially reduced.
- the sealing composition should form a substantially impenetrable barrier that eliminates, or at least partially reduces, the migration of any fluids between the water-bearing zone 14 and the hydrocarbon-bearing zone 12, or vice versa.
- the sealing composition should be able to penetrate into the formation and form an artificial barrier therein that plugs off pore spaces to water flow. Examples of suitable sealing compositions are described in more detail below.
- any suitable technique may be used for the delivery of the sealing composition into the portion of the hydrocarbon-bearing zone 12 surrounding the first interval 22.
- bull heading, coil tubing or jointed pipe e.g., with straddle packers, jetting tools, etc.
- the sealing composition may be injected into the hydrocarbon- bearing formation 12 by the jetting tool 28 while the jetting tool 28 is still in position in the well bore 10.
- the jetting tool 28 may be used for the delivery of the sealing composition into the portion of the hydrocarbon-bearing formation 12 that surrounds the first interval 22.
- Utilization of jetting tool 28 may reduce the need for equipment, such as packers, to isolate the treated interval (e.g., first interval 22).
- the sealing composition may be injected through the amulus 42 between the work string 32 and the casing 16.
- the sealing composition may be introduced into the hydrocarbon-bearing formation 12 at matrix flow rates.
- the sealing composition may be introduced at a flow rate in the range of from about 0.25 barrels to about 3 barrels per minute, depending, for example, on the length of the first interval 22.
- these flow rates are merely exemplary, and the present invention is applicable to flow rates outside these ranges.
- a sufficient amount of the sealing composition should be introduced such that the sealing composition has the desired penetration into the formation.
- a sufficient amount of the sealing composition may be introduced such that it penetrates in the range of from about 5 feet to about 50 feet into the formation.
- the depth of penetration of the sealing composition into the formation will vary, for example, based on the particular application.
- exemplary embodiments of the present invention may comprise perforating a second interval 34 of the well bore 10, and introducing a consolidating fluid into the portion of the subterranean formation surrounding the . second interval 34.
- the second interval 34 may be located above the first interval 22 so that the artificial barrier 24 prevents, or at least substantially reduces, water flow from the water-bearing formation 14 to the portion of the hydrocarbon bearing zone 12 surrounding the second interval 34. In this manner, the undesired production of water and particulates may be controlled once the well is put on production, in accordance with exemplary embodiments.
- the second interval 34 may have any suitable length (L) for the desired consolidation and production rate. Those of ordinary skill in the art will appreciate that the (L) of the second interval 34 will vary based on a number of factors, including, for example, costs and the desired production rate.
- exemplar ⁇ ' embodiments of the present invention may include perforating the second interval 34 of the well bore 10.
- perforations 36 may be formed in the second interval 34 that penetrate through the casing 16 and the cement sheath 18 and into the formation.
- the portion of the hydrocarbon-bearing zone 12 surrounding the second interval 34 may then be treated through the perforations 36 with a consolidating fluid for controlling particulate production.
- the second interval 34 may be perforated using any suitable technique
- an exemplary embodiment utilizes the jetting tool 28. Exemplary embodiments of the jetting tool 28 are described above with respect to perforating the first interval 22.
- the jetting tool 28 may be positioned in the well bore 10 adjacent the portion of the well bore 10 to be perforated, such as the second interval 34.
- the jetting tool 28 may be raised from the first interval 22 to the second interval 34.
- a fluid may be pumped down through the work string 32, into the jetting tool 28, out through the ports 30, and against the interior surface of the casing 16 causing the perforations 36 to be formed through the casing 16 and the cement sheath 18.
- abrasives e.g., sand
- sand may be included in the jetted fluid.
- a consolidating fluid may be introduced into the portion of the subterranean formation surrounding the second interval 34 to consolidate the treated portion of the formation into a consolidated region 38.
- the consolidating fluid should be any suitable fluid for enhancing the grain-to-grain (or grain- to-formation) contact between particulates in the treated portion of the subterranean formation so that the particulates are stabilized, locked in place, or at least partially immobilized such that they are resistant to flowing with produced or injected fluids. Accordingly, after treatment with the consolidating fluid, the particulates in the consolidated region 38 should be inhibited from migrating with any subsequently produced or injected fluids.
- any suitable technique may be used for the deliver ⁇ ' of the consolidating fluid into the second interval 34, for example, bull heading, coil tubing or jointed pipe (e.g., with straddle packers, jetting tools, etc.), or any other suitable technique may be used.
- the jetting tool 28 may be used for the delivery of the consolidating fluid into the portion of the hydrocarbon-bearing zone 12 that surrounds the second interval 34. Utilization of the jetting tool 28 may reduce the need for additional equipment (e.g., packers) to isolate the second interval 34.
- the consolidating fluid may be introduced into the hydrocarbon-bearing formation 12 at matrix flow rates.
- the consolidating fluid may be introduced at a flow rate in the range of from about 0.25 barrels to about 3 barrels per minute, depending on, for example, the length of perforated interval.
- these flow rates are merely exemplary, and the present invention is applicable to flow rates outside these ranges.
- the consolidating fluid should achieve sufficient penetration into the formation for the particular application.
- the consolidating fluid may be introduced into the near well bore portion of the formation surrounding the second interval 34.
- consolidation of the near well bore portion of the formation may alleviate potential problems associated with particulate production and thus help to control such undesired particulate production.
- the "near well bore portion" of a formation generally refers to the portion of a subterranean formation surrounding a well bore.
- the “near well bore portion” may refer to the portion of the formation surrounding a well bore and having a depth of penetration of from about 1 to about 3 well bore diameters.
- the depth of penetration of the consolidating fluid into the formation may vary based on the particular application.
- this invention is not limited to such order of treatment.
- the order of treatment may be reversed in that treatment of the second interval 34 with the consolidating fluid may occur prior to treatment of the first interval 22 with the sealing composition.
- the well bore 10 optionally may be shut in for a period of time.
- the shutting in of the well bore 10 for a period of time may, inter alia, enhance the coating of the consolidating fluid onto the particulates and minimize the washing away of the consolidating fluid during any later subterranean operations.
- the necessary shut-in time period is dependent, among other things, on the composition of the consolidating fluid used and the temperature of the formation. Generally, the chosen period of time may be between about 0.5 hours and about 72 hours or longer. Determining the proper period of time to shut in the formation is within the ability of one skilled in the art with the benefit of this disclosure.
- fracturing step may be used to reconnect the well bore 10 with portions of the formation outside the consolidated region 38.
- one or more fractures 40 may be created or enhanced through the consolidated region 38 and into the surrounding formation to at least partially restore effective permeability to the consolidated region.
- enhancing refers to the extension or enlargement of a natural or previously created fracture in the formation.
- the fracturing step may be accomplished by any suitable methodology.
- a hydraulic-fracturing treatment may be used that includes introducing a fracturing fluid into the consolidated region 38 at a pressure sufficient to create or enhance one or more fractures 40.
- the fracturing step may utilize the j etting tool 28.
- the j etting tool 28 may be used to initiate one or more fractures 40 in the consolidated region 38 by way of jetting a fluid through the perforations 36 and against the consolidated region 38.
- a fracturing fluid may also be pumped down through the annulus 42 between the work string 32 and the casing 16 and then into the consolidated region 38 at a pressure sufficient to create or enhance the one or more fractures 40.
- the fracturing fluid may be pumped down through the annulus 42 concurrently with the jetting of the fluid.
- a suitable fracturing treatment is CobraMax M Fracturing Service, available from Halliburton Energy Services, Inc.
- the fracturing fluid may comprise a viscosified fluid (e.g., a gel or a crosslinked gel).
- the fracturing fluid further may comprise proppant 44 that is deposited in the one or more fractures 40 to generate propped fractures.
- the proppant 44 majr be coated with a consolidating agent (e.g., a curable resin, a tackifying agent, etc.) so that the coated proppant forms a bondable, permeable mass in the one or more fractures 40, for example, to mitigate proppant flow back when the well is placed into production.
- the proppant may be coated with an ExpediteTM resin system, available from Halliburton Energy Services, Inc.
- one or more after- flush fluids may be used to at least partially restore permeability to the consolidated region 38, if desired.
- the after-flush fluid may be introduced into the consolidated region 38 while the consolidating fluid is still in a flowing state.
- the after-flush fluid generally acts to displace at least a portion of the consolidating fluid from flow paths in the consolidated region 38 and to force the displaced portions of the consolidating fluid further into the formation where it may have negligible impact on subsequent production.
- sufficient amounts of the consolidating fluid should remain in the consolidated region 38 to provide effective stabilization of the particulates therein.
- the after-flush fluid may be any fluid that does not undesirably react with the other components used or the subterranean formation.
- the after-flush fluid may be an aqueous-based fluid, a non-aqueous based fluid (e.g., kerosene, toluene, diesel, or crude oil), or a gas (e.g., nitrogen or carbon dioxide).
- one or more pre-flush fluids may be introduced into the portion of the hydrocarbon-bearing zone 12 surrounding second interval 34.
- the pre-flush fluid may be introduced into the formation to, for example, cleanout undesirable substances (e.g., oil, residue, or debris) from pore spaces in the matrix of the formation and/or to prepare the formation for subsequent placement of the consolidating fluid.
- an acidic pre-flush fluid may be used to, for example, dissolve undesirable substances in the formation.
- pre-flush fluids examples include aqueous-based fluid, a non-aqueous based fluid (e.g., kerosene, xylene, toluene, diesel, or crude oil), or a gas (e.g., nitrogen or carbon dioxide).
- Aqueous-based fluids may comprise fresh water, salt water, brines, sea water, or combinations thereof.
- one or more surfactants may be present in the pre-flush fluid, e.g., to aid a consolidating fluid in flowing to contact points between adjacent particulates in the formation.
- a sealing composition may be introduced into a portion of a subterranean formation to form an artificial barrier to water flow.
- the artificial barrier typically may be located between the waterbearing zone and the hydrocarbon-bearing zone so as to minimize the undesired production of water from the hydrocarbon-bearing zone
- the sealing composition may be any composition suitable for forming an artificial barrier in the treated portion of the subterranean formation such that the flow of water therethrough is eliminated or at least substantially reduced.
- suitable sealing compositions may include tackifying fluids, resin compositions, and gelable compositions.
- suitable sealing compositions may include fluids that comprise relative-permeability modifiers.
- the phrase "relative-permeability modifier" refers to compounds that should reduce a formation's effective permeability to water without a comparable reduction in the formation's effective permeability to hydrocarbons.
- these sealing compositions are merely exemplary, and the present invention is applicable to other compositions for forming a suitable artificial barrier to the flow of water. Examples of suitable sealing compositions will be described in more detail as follows.
- an exemplary embodiment of the sealing compositions used in the present invention may comprise a tackifying agent.
- Suitable tackifying agents are substances that are (or may be activated to become) tacky and thus adhere to unconsolidated particulates in the subterranean formation. In this manner, the tackifying agent may form a barrier in the treated portion of the formation.
- Suitable tackifying agents may not be significantly tacky when placed into the formation, but may be capable of being "activated" (that is destabilized, coalesced and/or reacted) to transform into a tacky compound at a desirable time. Such activation may occur before, during, or after the introduction of the tackifying fluid into the subterranean formation.
- One type of tackifying agent suitable for use includes a non-aqueous tackifying agent.
- An example of a suitable non-aqueous tackifying agent comprises polyamides that are liquids or in solution at the temperature of the formation such that they are, by themselves, non-hardening when introduced into the subterranean formation.
- One exemplary embodiment of a suitable tackifying agent comprises a condensation reaction product that comprises commercially available polyacids and a polyamine. Such commercial products include compounds such as mixtures of C 36 dibasic acids containing some trimer and higher oligomers and also small amounts of monomer acids that are reacted with polyamines.
- polyacids include trimer acids, synthetic acids produced from fatty acids, maleic anhydride, acrylic acid, and the like.
- 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.
- An example of a suitable non- aqueous tackifying agent is Sand Wedge Enhancement System, available from Halliburton Energy Sendees, Inc.
- non-aqueous tackifying agents include liquids and solutions of, for example, polyesters, polycarbonates and polycarbamates, natural resins such as shellac and the like.
- suitable non-aqueous tackifying agents are described in U.S. Pat. Nos. 5,853,048 and 5,833,000, the disclosures of which are incorporated herein by reference.
- Non-aqueous tackifying agents may be either used such that they form a non- hardenitig coating or they may be combined with a multifunctional material capable of reacting with the tackifying compound to form a hardened coating.
- a “hardened coating” as used in this disclosure means that the reaction of the tackifying compound 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 compound alone with the particulates.
- the tackifying agent may function similarly to a hardenable resin.
- Multifunctional materials suitable for use in the present invention include aldehydes, 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, aldehyde condensates, and silyl-modified polyamide compounds and the like, and combinations thereof.
- 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, aldehyde condensates, and silyl-modified polyamide compounds and the like, and combinations thereof.
- Suitable silyl-modified polyamide compounds that may be used in exemplary embodiments of the present invention include those that are substantially self-hardening compositions 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.
- a polyacid e.g., diacid or higher
- a polyamine e.g., diamine or higher
- 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 exemplary embodiments, the multifunctional material may be 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 disclosure of which is incorporated herein by reference. [0048] Solvents suitable for use with the tackifying agents include any solvent that is compatible with the tackifying agent and achieves the desired viscosity effect.
- the solvents that can be used in exemplary embodiments of the present invention preferably include those having high flash points (e.g., above about 125°F).
- solvents suitable for use in exemplary embodiments of the present invention include butylglycidyl ether, dipropylene glycol methyl ether, butyl bottom alcohol, dipropylene glycol dimethyl ether, diethyleneglycol methyl ether, ethyl enegly col 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 subterran
- aqueous tackifying agent refers to a tackifying agent that is soluble in water.
- suitable aqueous tackifying agents generally comprise charged polymers, that when in an aqueous solvent or solution, enhance the grain-to-grain contact between the individual particulates within the formation (e.g., proppant, gravel particulates, formation particulates, or other particulates), and may help bring about the consolidation of the particulates into a cohesive, flexible, and permeable mass.
- aqueous tackifying agents suitable for use in an exemplary embodiment of the present invention include 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 copolymers, methacrylic acid derivative polymers, methacrylic acid homopolymers, methacrylic acid ester homopolymers (such as poly(methyl methacrylate), poly(butyl methacrylate), and poly(2-ethylhexyl methacrylate)), acrylamido-methyl-propane sulfonate polymers, acrylamido-methyl-propane sulfonate derivative polymers, acrylamido-methyl-propane sulfonate copolymers, and acrylic acid/acrylamido-methyl-propane sulfonate copo
- aqueous tackifying agents examples include FDP-S706-3 and FDP-S800-05, which are available from Halliburton Energy Services, Inc.
- suitable aqueous tackifying agents are described in U.S. Pat. No. 7,131,491 and U.S. Pat App. Pub. No. 2005/0277554, the disclosures of which are incorporated herein by reference.
- aqueous tackifying agent comprises a benzyl coco di-(hydroxyethyl) quaternary amine, p-T-amyl-phenol condensed with formaldehyde, or a copolymer comprising from about 80% to about 100% Ci -30 alkylmethacrylate monomers and from about 0% to about 20% hydropbilic monomers.
- 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 mixogen-containing groups.
- Suitable hydrophilic monomers include dialJkyl 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 acrylic acid, hydroxyethyl acrylate, acrylamide, and the like.
- These copolymers can be made by any suitable emulsion polymerization technique. Examples of suitable tackifying agents are described in U.S. Pat. No. 5,249,627, the disclosure of which is incorporated herein by reference. Methods of producing these copolymers are disclosed in U.S. Pat. No. 4,670,501, the disclosure of which is incorporated herein by reference.
- Resins suitable for use may include any suitable resin that is capable of forming a hardened, consolidated mass in the treated formation.
- 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.
- 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 combinations thereof.
- 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
- suitable resins such as epoxy resins
- suitable resins such as furan resins generally require a time-delayed catalyst or an external catalyst to help activate the polymerization of the resins if the cure temperature is low (e.g., less than 250° F) but will cure under the effect of time and temperature if the formation temperature is above about 250 0 F 5 preferably above about 300 0 F. 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 exemplary embodiments of the present invention and to determine whether a catalyst is needed to trigger curing.
- An example of a suitable resin is Sand Trap ® Formation Consolidation Service, available from Halliburton Energy Services, Inc.
- Selection of a suitable resin may be affected by the temperature of the subterranean formation to which the fluid will be introduced.
- a bottom hole static temperature BHST
- two-component epoxy-based resins comprising a hardenable resin component and a hardening agent component containing specific hardening agents may be preferred.
- a furan-based resin may be preferred.
- a phenolic-based resin or a one-component HT epoxy-based resin may be suitable.
- a phenol/phenol formaldehyde/furfuryl alcohol resin may also be suitable.
- any solvent that is compatible with the chosen resin and achieves the desired viscosity effect may be suitable for use with the resin.
- Some exemplary solvents are those having high flash points (e.g., about 125 0 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 formamide, diethyleneglycol methyl ether, ethyleneglycol butyl ether, diethyleneglycol butyl ether, propylene carbonate, methanol, butyl alcohol, d-limonene, fatty acid methyl esters, and combinations thereof.
- Suitable 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 C 2 to C 6 dihydric alkanol containing at least one C 1 to C 6 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.
- suitable gelable compositions should cure to form a gel.
- Gelable compositions suitable for use in exemplary embodiments of the present invention include those compositions that cure to form a semi-solid, immovable, gel-like substance. Prior to curing, the gelable compositions should have low viscosities and be capable of flowing in pipe and into the subterranean formation.
- the gelable composition may be any gelable liquid composition capable of converting into a gelled substance that substantially plugs the permeability of the formation. Accordingly, once placed into the formation, the gelable composition should form the desired artificial barrier.
- suitable gelable compositions include gelable aqueous silicate compositions, crosslinkable aqueous polymer compositions, gelable resins and polymerizable organic monomer compositions. Examples of suitable gelable compositions will be described in more detail as follows.
- the gelable compositions may comprise a gelable aqueous silicate composition.
- Suitable gelable aqueous silicate compositions for barrier formation generally comprise aqueous alkali metal silicate solution and a catalyst (e.g., a temperature-activated catalyst) for gelling the aqueous alkali metal silicate solution.
- a catalyst e.g., a temperature-activated catalyst
- An example of a suitable gelable aqueous silicate composition is InjectrolTM, which is available from Halliburton Energy Services, Inc.
- suitable gelable aqueous silicate compositions are described in U.S. Pat. No. 4,466,831, the disclosure of which is incorporated herein by reference.
- the aqueous alkali metal silicate solution component of the gelable aqueous silicate compositions generally may comprise 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.
- suitable alkali metal silicates include one or more of sodium silicate, potassium silicate, lithium silicate, rubidium silicate, or cesium silicate.
- the sodium silicate that may be used in the aqueous alkali metal silicate solution may have a Na 2 OtO-SiO 2 weight ratio in the range of from about 1 :2 to about 1 :4.
- the sodium silicate may have a Na 2 CMo-SiO 2 weight ratio in the range of about 1 :3.2.
- the alkali metal silicate ma ⁇ ' be 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.
- 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, gel-like 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 that can be used in the gelable aqueous silicate compositions of exemplary embodiments 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 24O 0 F); sodium acid pyrophosphate (which is most suitable in the range of from about 6O 0 F to about 240 0 F); citric acid (which is most suitable in the range of from about 6O 0 F to about 120 0 F); and ethyl acetate (which is most suitable in the range of from about 6O 0 F to about 120 0 F).
- the temperature-activated catalyst may be present in the gelable aqueous silicate composition in the range of from about 0.1% to about 5% by weight of the gelable aqueous silicate composition.
- the gelable compositions may comprise a crosslinkable aqueous polymer composition.
- Suitable crosslinkable aqueous polymer compositions for barrier formation generally comprise an aqueous solvent, a crosslinkable polymer, and a crosslinking agent.
- Such compositions are similar to those used to form gelled treatment fluids, such as fracturing fluids, but, according to the methods of exemplary embodiments of the present invention, they are not exposed to breakers or de-linkers so they retain their viscous nature over time.
- suitable compositions should generally be resistant to breaking, for example, due to formation temperatures.
- An example of a suitable crosslinkable polymer composition is H2-ZeroTM, which is commercially available from Halliburton Energy Services, Lac. Examples of suitable crosslinkable aqueous polymer compositions are described in U.S. Pat. Nos. 5,836,392, 6,192,986, and 6,196,317, the disclosures of which are incorporated herein by reference.
- 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.
- 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 exemplary embodiments of the present invention or with the subterranean formation.
- crosslinkable polymers that can be used in the crosslinkable aqueous polymer compositions include carboxylate-containing polymers and acrylamide- containing polymers.
- suitable acrylamide-containing polymers include polyacrylamide, partially hydrolyzed polyacrylamide, copolymers of acrylamide and acrylate, copolymers of acrylamide and 2-acrylamido-2-methylpropanesulfonic acid, carboxylate- containing terpolymers and tetrapolymers of acrylate.
- Suitable crosslinkable polymers include hydratable polymers comprising polysaccharides and derivatives thereof and that contain one or more of the monosaccharide unit's 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 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.
- the crosslinkable polymer may be 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.
- the crosslinkable polymer may be 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.
- the crosslinkable aqueous polymer compositions of exemplary embodiments of the present invention further comprise a crosslinking agent for crosslinking the crosslinkable polymers to form the desired gelled substance.
- the crosslinking agent may be a molecule or complex containing a reactive transition metal cation.
- An exemplary crosslinking agent comprises trivalent chromium cations complexed or bonded to anions, atomic oxygen, or water.
- suitable crosslinking agents include 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.
- Organic crosslinkers may also be suitable, in certain exemplary embodiments. Examples of suitable organic crosslinkers include polyalkyleneimines, polyalkylenepolyamines (e.g., polyethyleneimine), chitosan, and mixtures thereof.
- the crosslinking agent should be present in the crosslinkable aqueous polymer compositions of exemplary embodiments of the present invention in an amount sufficient to provide, inter alia, the desired degree of crosslinking.
- the crosslinking agent may be present in the crosslinkable aqueous polymer compositions of the present invention in an amount in the range of from about 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.
- the crosslinkable aqueous polymer compositions may further comprise a crosslinking delaying agent, such as a polysaccharide crosslinking delaying agent 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, such as after placement into the formation.
- a crosslinking delaying agent such as a polysaccharide crosslinking delaying agent 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, such as after placement into the formation.
- One of ordinary skill in the art, with the benefit of this disclosure, will be able to determine appropriate amount of the crosslinking delaying agent to
- Certain exemplary embodiments of the gelable compositions comprise gelable resin compositions that cure to form flexible gels. Unlike the curable resin compositions described below with respect to the consolidating fluids, which cure into hardened masses, the gelable resin compositions cure into flexible, gelled substances that form resilient gelled substances between the particulates of the treated zone of the unconsolidated formation.
- the gelable resin compositions useful in accordance with exemplary embodiments of the present invention comprise a curable resin, a solvent, and a catalyst.
- the compositions typically may form the semi-solid, gelled substances described above.
- the curable resin compositions may further comprise one or more "flexibilizer additives" (described in more detail below) to provide flexibility to the cured compositions.
- gelable resins examples include organic resins such as polyepoxide resins (e.g., Bisphenol a- epichlorohydrin resins), polyester resins, urea-aldehyde resins, furan resins, urethane resins, and mixtures thereof.
- organic resins such as polyepoxide resins (e.g., Bisphenol a- epichlorohydrin resins), polyester resins, urea-aldehyde resins, furan resins, urethane resins, and mixtures thereof.
- any solvent that is compatible with the gelable resin and achieves the desired viscosity effect is suitable for use in exemplary embodiments of the present invention.
- solvents that may be used in the gelable resin compositions of the present invention include phenols, formaldehydes, furfuryl alcohols, furfurals, alcohols, ethers such as butyl glycidyl ether and cresyl glycidyl etherphenyl glycidyl ether, and combinations thereof.
- the solvent comprises butyl lactate.
- the solvent may be used to reduce the viscosity of the gelable resin composition from about 3 to about 3,000 centipoises ("cP") at 8O 0 F.
- the solvent acts to provide flexibility to the cured composition.
- the solvent may be included in the gelable resin composition in an amount sufficient to provide the desired viscosity effect.
- the solvent used is included in the gelable resin composition in amount in the range of from about 5% to about 75% by weight of the curable resin.
- any catalyst that may be used to cure an organic resin is suitable for use in exemplary embodiments of the present invention.
- Suitable catalysts include internal and external catalysts.
- the catalyst chosen is an amide or a polyamide
- no flexibilizer additive should be required because, inter alia, such catalysts should cause the gelable resin composition to convert into the desired semi-solid, gelled substance.
- Other suitable catalysts such as an amine, a polyamine, methylene dianiline, and other curing agents known in the art
- the catalyst used is included in the gelable 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 exemplary embodiments of the present invention, the catalyst used is included in the gelable resin composition in an amount in the range of from about 20% to about 75% by weight of the curable resin.
- flexibilizer additives may be used, inter alia, to provide flexibility to the gelled substances formed from the curable resin compositions.
- Flexibilizer additives may be used where the catalyst chosen would cause the gelable resin composition to cure into a hard and brittle material rather than a desired gelled substance.
- flexibilizer additives may be used where the catalyst chosen is not an amide or polyamide.
- suitable flexibilizer additives include an organic ester, an oxygenated organic solvent, an aromatic solvent, and combinations thereof. Of these, ethers, such as diburyl phthalate, may be used in certain exemplary embodiments.
- the flexibilizer additive may be included in the gelable 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. 4.
- suitable polymerizable organic monomer compositions for use in the sealing compositions generally comprise an aqueous solvent, a water-soluble polymerizable organic monomer, an oxygen scavenger, and a primary initiator.
- An example of a suitable polymerizable organic monomer composition is Perm-SealTM, which is available from Halliburton Energy Sendees, Inc.
- Examples of suitable polymerizable organic monomer compositions are described in U.S. Pat. Nos. 5,358,051 and 5,335,726, the disclosures of which are incorporated herein by reference.
- the aqueous solvent 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.
- a variety of monomers are suitable for use as the water-soluble polymerizable organic monomers in exemplary embodiments of the present invention.
- suitable monomers include acrylic acid, methacrylic acid, acrylamide, methacrylamide, 2- methacrylamido-2-methylpropane sulfonic acid, 2-dimethylacrylamide, vinyl sulfonic acid, N,N-dimethylaminoethyhnethacrylate, 2-triethylammoniumethylmethacrylate chloride, N,N- dimethyl-aminopropylmethacryl-arnide, memacrylainidepropyltriemylammonium chloride, N-vinyl pyrrolidone, vinyl-phosphonic acid, and methacryloyloxyethyl trimethylammonium sulfate, and mixtures thereof.
- the water-soluble polymerizable organic monomer may be self-crosslinking.
- suitable monomers which are self- crosslinking include hydroxyethylacrylate, hydroxymethylacrylate, hydroxyethylmethacrylate, N-hydroxymethylacrylamide, N-hydroxymethyl-methacrylamide, polyethylene glycol acrylate, polyethylene glycol methacrylate, polypropylene gylcol acrylate, polypropylene glycol methacrylate, and mixtures thereof.
- hydroxyethylacrylate may be used in certain exemplary embodiments.
- One example particular of a suitable monomer is hydroxyethylcelh ⁇ lose- vinyl phosphoric acid.
- 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.
- the water-soluble polymerizable organic monomer is 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.
- the water-soluble polymerizable organic monomer is 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.
- an oxygen scavenger such as stannous chloride
- the stannous chloride may be pre-dissolved in a hydrochloric acid solution.
- 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.
- the stannous chloride may be included in the polymerizable organic monomer composition of an exemplary embodiment 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.
- the primary initiator is used, inter alia, to initiate polymerization of the water- soluble polymerizable organic monomer(s) used in an exemplary embodiment of the present invention.
- Any compound or compounds that 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 present in the polymerizable organic monomer composition.
- Compounds suitable for use as the primary initiator include 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.
- 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).
- 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).
- 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.
- 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).
- the polymerizable organic monomer compositions of exemplary embodiments of the present invention further may comprise a crosslinking agent for crosslinking the polymerizable organic monomer compositions in the desired gelled substance
- the crosslinking agent is a molecule or complex containing a reactive transition metal cation, such as, e.g., trivalent chromium cations complexed or bonded to anions, atomic oxygen, or water.
- suitable crosslinking agents include compounds or complexes containing chromic acetate and/or chromic chloride.
- Other suitable transition metal cations include chromium VI within a redox system, aluminum III, iron II, iron III, and zirconium IV.
- the crosslinking agent 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.
- fluids that comprise a relative-permeability modifier may be used as the sealing compositions, in accordance with exemplary embodiments of the present invention.
- the relative-permeability modifier generally may not plug pore spaces within the treated formation to block flow therethrough, the relative-permeability modifier should adsorb onto surfaces within the formation so as to selectively reduce the formation's water permeability.
- the formation may be treated with the relative- permeability modifier to form an artificial barrier in the treated formation that at least partially reduces the flow of water therethough.
- the relative-permeability modifier should be included in the fluid in an amount sufficient to provide the desired artificial barrier.
- the relative-permeability modifier may be included in the fluid in an amount in the range of from 0.01% to about 10% by weight of the fluid.
- the relative- permeability modifier maybe included in the fluid in an amount in the range of from about 0.1% to about 1 % by weight of the fluid.
- suitable relative-permeability modifiers may be any compound capable of selectively reducing the effective permeability of a formation to water without a comparable reduction of the formation's effective permeability to hydrocarbons.
- suitable relative-permeability modifiers may be any compound capable of selectively reducing the effective permeability of a formation to water without a comparable reduction of the formation's effective permeability to hydrocarbons.
- water-soluble polymers may be suitable for use as the relative-permeability modifiers.
- suitable water-soluble polymers include homo-, co-, and terpolymers of acrylamide, 2-acrylamido-2-methyl propane sulfonic acid, N,N-dimethylacrylamide, vinyl pyrrolidone, dimethylamfnoethyl methacrylate, acrylic acid, dimethylaminopropyhnethacrylamide, vinyl amine, vinyl acetate, trimethylammoniumethyl methacrylate chloride, methacrylamide, hydroxyethyl acrylate, vinyl sulfonic acid, vinyl phosphomc acid, methacrylic acid, vinyl caprolactam, N- vinylformamide, N,N-diallylacetamide, dimethyldiallyl ammonium halide, itaconic acid, styrene sulfonic acid, methacrylamidoethyltrimethyl ammonium halide, quaternary salt derivatives of acrylamide quaternary salt derivatives of acrylic acid, and combinations thereof.
- water-soluble polymers suitable for use as relative-permeability modifiers also may include hydrophobically modified polymers.
- hydrophobically modified polymers refers to the incorporation into the hydrophilic polymer structure of hydrophobic groups, wherein the alkyl chain length is from about 4 to about 22 carbons. While these hydrophobically modified polymers have hydrophobic groups incorporated into the hydrophilic polymer structure, they should remain water-soluble.
- a mole ratio of a hydrophilic monomer to the hydrophobic compound in the hydrophobically modified polymer is in the range of from about 99.98:0.02 to about 90:10, wherein the hydrophilic monomer is a calculated amount present in the hydrophilic polymer.
- the hydrophobically modified polymers may comprise a polymer backbone that comprises polar heteroatoms.
- the polar heteroatoms present within the polymer backbone of the hydrophobically modified polymers include, but are not limited to, oxygen, nitrogen, sulfur, or phosphorous.
- Exemplary hydrophobically modified polymers may be synthesized utilizing any suitable technique.
- the hydrophobically modified polymers may be a reaction product of a hydrophilic polymer and a hydrophobic compound.
- the hydrophobically modified polymers may be prepared from a polymerization reaction comprising a hydrophilic monomer and a hydrophobically modified hydrophilic monomer.
- the hydrophobically modified polymers may be pre-reacted before they are placed into the well bore 10.
- the hydrophobically modified polymers may be prepared by an appropriate in situ reaction. Suitable hydrophobically modified polymers and methods for their preparation are described in more detail in U.S. Pat. Nos. 6,476,169 and 7,117,942, the disclosures of which are incorporated herein by reference. Those of ordinary skill in the art, with the benefit of this disclosure, will be able to determine other suitable methods for the synthesis of suitable hydrophobically modified polymers.
- suitable hydrophobically modified polymers may be synthesized by the hydrophobic modification of a hydrophilic polymer.
- the hydrophilic polymers suitable for forming the hydrophobically modified polymers used in the present invention should be capable of reacting with hydrophobic compounds.
- Suitable hydropbilic polymers include, homo-, co-, or terpolymers such as, but not limited to, polyacrylamides, polyvinylamines, poly(vinylamines/vinyl alcohols), alkyl acrylate polymers in general, and combinations thereof.
- alkyl acrylate polymers include polydimethylaminoethyl methacrylate, polydimethylaminopropyl methacrylamide, poly(acrylamide/dmie1hylarninoethyl methacrylate), poly(methacrylic acid/dimethylaminoethyl methacrylate), poly(2-acrylamido- 2-methyl propane sulfonic acid/dimethylaminoethyl methacrylate), poly(acrylamide/dimethylaminopropyl methacrylamide), P°ly (acrylic acid/dimethylaminopropyl methacrylamide), and poly(methacrylic acid/dimethylaminopropyl methacrylamide).
- the hydrophilic polymers comprise a polymer backbone and reactive amino groups in the polymer backbone or as pendant groups, the reactive amino groups capable of reacting with hydrophobic compounds.
- the hydrophilic polymers comprise dialkyl amino pendant groups.
- the hydrophilic polymers comprise a dimethyl amino pendant group and a monomer comprising dimethylam ⁇ noethyl methacrylate or drmethylaminopropyl methacrylamide.
- the hydrophilic polymers comprise a polymer backbone that comprises polar heteroatoms, wherein the polar heteroatoms present within the polymer backbone of the hydrophilic polymers include oxygen, nitrogen, sulfur, or phosphorous.
- Suitable hydrophilic polymers that comprise polar heteroatoms within the polymer backbone include homo-, co-, or terpolymers, such as, but not limited to, celluloses, chitosans, polyamides, polyetheramines, polyethyleneimines, polyhydroxyetherarnines, polylysines, polysulfones, gums, starches, and combinations thereof.
- the starch is a cationic starch.
- a suitable cationic starch may be formed by reacting a starch, such as corn, maize, waxy maize, potato, tapioca, or the like, with the reaction product of epichlorohydrin and trialkylamine.
- the hydrophobic compounds that are capable of reacting with the hydrophilic polymers include alkyl halides, sulfonates, sulfates, organic acids, and organic acid derivatives.
- suitable organic acids and derivatives thereof include octenyl succinic acid; dodecenyl succinic acid; and anhydrides, esters, imides, and amides of octenyl succinic acid or dodecenyl succinic acid.
- the hydrophobic compounds may have an alkyl chain length of from about 4 to about 22 carbons. In another exemplary embodiment, the hydrophobic compounds may have an alkyl chain length of from about 7 to about 22 carbons.
- the hydrophobic compounds may have an alkyl chain length of from about 12 to about 18 carbons.
- the reaction between the hydrophobic compound and hydrophilic polymer may result in the quaternization of at least some of the hydrophilic polymer amino groups with an alkyl halide, wherein the alkyl chain length is from about 4 to about 22 carbons.
- suitable hydrophobically modified polymers also may be prepared from a polymerization reaction comprising a hydrophilic monomer and a hydrophobically modified hydrophilic monomer.
- the hydrophobically modified polymers synthesized from the polymerization reactions may have estimated molecular weights in the range of from about 100,000 to about 10,000,000 and mole ratios of the hydrophilic monomer(s) to the hydrophobically modified hydrophilic monomer(s) in the range of from about 99.98:0.02 to about 90:10.
- hydrophilic monomers may be used to form the hydrophobically modified polymers useful in the present invention.
- suitable hydrophilic monomers include acrylamide, 2-acrylamido-2-methyl propane sulfonic acid, N,N- dimethylacrylamide, vinyl pyrrolidone, dimethylaminoethyl methacrylate, acrylic acid, dimemylaminopropylmethacrylamide, vinyl amine, vinyl acetate, Mmethylamrnoniurnethyl methacrylate chloride, methacrylamide, hydroxyethyl acrylate, vinyl sulfonic acid, vinyl phosphonic acid, methacrylic acid, vinyl caprolactam, N-vinylformamide, N,N- diallylacetamide, dimethyldiallyl ammonium halide, itaconic acid, styrene sulfonic acid, methacrylamidoethyltrimethyl ammonium halide, quaternary salt derivatives of acryl
- hydrophobically modified hydrophilic monomers also may be used to form the hydrophobically modified polymers useful in exemplary embodiments of the present invention.
- suitable hydrophobically modified hydrophilic monomers include alkyl acrylates, alkyl methacrylates, alkyl acrylamides, alkyl methacrylamides alkyl dimethylammoniumethyl methacrylate halides, and alkyl dimethylammoniumpropyl methacrylamide halides, wherein the alkyl groups have from about 4 to about 22 carbon atoms. In another exemplary embodiment, the alkyl groups have from about 7 to about 22 carbons. In another exemplary embodiment, the alkyl groups have from about 12 to about 18 carbons.
- the hydrophobically modified hydrophilic monomer comprises octadecyldimethylarnmoniumethyl methacrylate bromide, hexadecyldimethylammoniumethyl methacrylate bromide, hexadecyldimethylammoniumpropyl methacrylamide bromide, 2-ethylhexyl methacrylate, or hexadecyl methacrylamide.
- Suitable hydrophobically modified polymers that may be formed from the above-described reactions include acrylamide/octadecyldimethylammoriiumethyl methacrylate bromide copolymer, dimethylamino ethyl methacrylate/vinyl pyrrolidone/hexadecyldimethylammoniumethyl methacrylate bromide terpolymer, and acrylamide/2-acrylainido-2-methyl propane sulfonic acid/2-ethylhexyl methacrylate terpolymer.
- Another suitable hydrophobically modified polymer formed from the above- described reaction comprises an amino methacrylate/alkyl amino methacrylate copolymer.
- a suitable dimethlyaminoethyl memacrylate/alkyl-dimethylammoniumethyl methacrylate copolymer is a dimethylaminoethyl methacrylate/hexadecyl-dimethylammoniumethyl methacrylate copolymer.
- these copolymers may be formed by reactions with a variety of alkyl halides.
- the hydrophobically modified polymer may comprise a dimethylaminoethyl methacrylate/hexadecyl-dimethylammoniumethyl methacrylate bromide copolymer.
- a consolidating fluid may be introduced into a portion of a subterranean formation to consolidate the treated portion of the formation.
- the consolidating fluid may be any fluid suitable for enhancing the grain-to-grain (or grain-to-formation) contact between particulates in the treated portion of the subterranean formation so that the particulates are stabilized, locked in place, or at least partially immobilized such that they are resistant to flowing with any produced or injected fluids.
- the consolidating fluid should inhibit dislodged fines from migrating with any subsequently produced or injected fluids.
- suitable consolidating fluids include tackifying fluids, resin compositions, and gelable compositions.
- an exemplary embodiment of the consolidating fluids used in the present invention may comprise a tackifying agent.
- Suitable tackifying agents are substances that are (or may be activated to become) tacky and, thus, impart a degree of consolidation to unconsolidated particulates in the subterranean formation. In this manner, the particulates may be stabilized, locked in place, or at least partially immobilized such that they are resistant to flowing with fluids that are subsequently produced or injected.
- Suitable tackifying agents may not be significantly tacky when placed into the formation, but may be capable of being "activated" (that is destabilized, coalesced and/or reacted) to transform into a tacky compound at a desirable time. Such activation may occur before, during, or after the introduction of the tackifying fluid into the subterranean formation. Examples of suitable tackifying agents are described in more detail above with respect to the exemplar ⁇ ' sealing compositions.
- a consolidating fluid that may be used in an exemplary embodiment of the present invention may comprise a resin.
- Resins suitable for use may include any resin that is capable of consolidating the treated formation into a hardened, consolidated mass. Examples of suitable resins are described in more detail above with respect to the exemplary sealing compositions.
- suitable gelable compositions should cure to form a gel.
- Gelable compositions suitable for use in exemplary embodiments of the present invention include those compositions that cure to form a semi-solid, immovable, gel-like substance. Prior to curing, the gelable compositions should have low viscosities and be capable of flowing in pipe and into the subterranean formation.
- the gelable composition may be 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.
- the term "flexible” refers to a state wherein the treated formation is relatively malleable and elastic and able to withstand substantial pressure cycling without substantial breakdown of the formation.
- the resultant gelled substance stabilizes the treated portion of the formation while allowing the formation to absorb the stresses created during pressure cycling.
- the gelled substance may aid in preventing breakdown of the formation both by stabilizing and by adding flexibility to the treated region.
- Exemplary gelable compositions are described in more detail above with respect to the exemplary sealing compositions.
Abstract
Disclosed embodiments relate to methods of completing wells in subterranean formations. An exemplary embodiment comprises forming an artificial barrier to water flow, wherein the artificial barrier is located at or above a hydrocarbon-water interface between a water-bearing formation zone and a hydrocarbon-bearing formation zone. The exemplary embodiment further comprises consolidating a portion of the hydrocarbon-bearing formation zone, wherein the artificial barrier is located between the consolidated portion of the hydrocarbon-bearing formation zone and the water-bearing formation zone.
Description
METHODS OF COMPLETING WELLS FOR CONTROLLING WATER AND PARTICULATE PRODUCTION
BACKGROUND
[0001] The present disclosure relates to methods of completing wells in subterranean formations, such as in unconsolidated subterranean formations. More particularly, the present disclosure relates to methods of completing wells in unconsolidated subterranean formations for controlling water and particulate production.
[0002] Before desirable fluids (e.g., oil, gas, etc.) may be produced from a well bore that has been drilled into a subterranean formation, the well typically must be completed. Well completions may involve a number of stages, including the installation of additional equipment into the well and the performance of procedures to prepare the well for production. By way of example, well completions may include perforating casing that is cemented into the well bore so that fluids can flow, for example, from the formation and into the well bore. Completing the well may also include the installation of production tubing inside the well bore through which fluids may be produced from the bottom of the well bore to the surface. Well completions also may involve a number of other procedures performed in the well and to the surrounding formation, for example, to address issues related to undesired particulate and water production.
[0003] Additional procedures also may be needed when wells are completed in certain portions of a subterranean formation, such as in unconsolidated subterranean formations, to prevent undesirable particulate production. As used in this disclosure, the phrase "unconsolidated subterranean formation" refers to a subterranean formation that contains loose particulates and/or particulates bonded with insufficient bond strength to withstand forces created by the production (or injection) of fluids through the formation. These particulates present in the unconsolidated subterranean formation may include, for example, sand, crushed gravel, crushed proppant, fines, and the like. When the well is placed into production, these particulates may migrate out of the formation with the fluids produced by the wells. The presence of such particulates in produced fluids may be undesirable in that the particulates may, for example, abrade downhole and surface equipment (e.g., pumps, flow lines, etc.) and/or reduce the production of desired fluids from the well. By way of example,
the migrating particulates may clog flow paths, such as formation pores, perforations, and the like, thereby reducing production.
[0004] A number of well completion techniques have been developed to control particulate production in unconsolidated subterranean formations. One technique of controlling particulate production includes placing a filtration bed containing gravel (e.g., a "gravel pack") near the well bore to provide a physical barrier to the migration of particulates with the production (or injection) of fluids. Typically, such "gravel-packing operations" involve the pumping and placement of a quantity of gravel into the unconsolidated 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.
[0005] Another technique used to control particulates in unconsolidated formations involves application of a consolidating fluid (e.g., resins, tackiflers, etc.) to consolidate portions of the unconsolidated formation into stable, permeable masses. In general, the consolidating fluid should enhance the grain-to-grain (or grain-to-formation) contact between particulates in the treated portion of the subterranean formation so that the particulates are stabilized, locked in place, or at least partially immobilized such that they are resistant to flowing with produced or injected fluids.
[0006] In addition, the undesired production of water may constitute a major expense in the production of hydrocarbons from subterranean formations, for example, due to the energy expended in producing, separating, and disposing of the water. In addition, when produced through unconsolidated subterranean formations, the water may also have an undesirable effect on the migration of formation sands. While wells are typically completed in hydrocarbon-producing formations, a water-bearing zone may occasionally be adjacent to the hydrocarbon-producing formation. In some instances, the water may be communicated with the hydrocarbon-producing formation by way of fractures and/or high-permeability streaks. In addition, undesired water production may be caused by a variety of other occurrences, including, for example, water coning, water cresting, bottom water, channeling
at the well bore (e.g., channels behind casing formed by imperfect bonding between cement and casing), and the like.
[0007] Accordingly, well completions may include procedures to address issues that may be encountered with the undesired production of water. One attempt to address these issues has been to inject sealing compositions into the formation to form an artificial barrier between the water-bearing zone and the hydrocarbon-producing formation. By way of example, a gelable fluid may be introduced into the formation in a flowable state and thereafter form a gel in the formation that plugs off formation flow paths to eliminate, or at least reduce, the flow of water. Crosslinkable gels have also been used in a similar manner. In addition, certain polymers (commonly referred to as "relative-permeability modifiers") may be used to reduce the formation's effective permeability to water without a comparable reduction in the formation's effective permeability to hydrocarbons. The use of relative- permeability modifiers may be desirable, for example, where hydrocarbons will be produced from the treated portion of the formation.
SUMMARY
[0008] The present disclosure relates to methods of completing wells in subterranean formations, such as in unconsolidated subterranean formations. More particularly, the present disclosure relates to methods of completing wells in unconsolidated subterranean formations for controlling water and particulate production.
[0009] An exemplary embodiment of the present invention provides a method of completing a well. The method comprises forming an artificial barrier to water flow, wherein the artificial barrier is located at or above a hydrocarbon-water interface between a waterbearing formation zone and a hydrocarbon-bearing formation zone. The method further comprises consolidating a portion of the hydrocarbon-bearing formation zone, wherein the artificial barrier is located between the consolidated portion of the hydrocarbon-bearing formation zone and the water-bearing formation zone.
[0010] Another exemplary embodiment of the present invention provides a method of completing a well for controlling water and particulate production. The method comprises identifying a hydrocarbon-water interface between a hydrocarbon-bearing formation zone and a water-bearing formation zone. The method further comprises perforating a first
interval of a casing, and introducing a sealing composition into one or more subterranean formations surrounding the first interval to form an artificial barrier to water flow. The artificial barrier is located either at or above the hydrocarbon-water interface. The method further comprises perforating a second interval of the casing, wherein the second interval is located above the first interval. The method further comprises introducing a consolidating fluid into one or more subterranean formations surrounding the second interval so as to consolidate at least a portion of the one or more subterranean formations.
[0011] Another exemplary embodiment of the present invention provides a method of completing a well for controlling water and particulate production. The method comprises positioning a jetting tool at a first location in a well bore and perforating a first interval of casing at the first location. The perforating of the first interval comprises using the jetting tool to form one or more perforations that penetrate through the casing. The method further comprises introducing a sealing composition through the jetting tool and into one or more subterranean formations surrounding the first interval to form an artificial barrier to water flow. Either the artificial barrier is adjacent to a hydrocarbon-water interface between a hydrocarbon-bearing formation zone and a water-bearing formation zone, or a bottom of the artificial barrier is located no more than about ten feet above the hydrocarbon-water interface. The method further comprises positioning the jetting tool in the well bore at a second location above the first location, and perforating a second interval of casing at the second location in the well bore. The perforating of the second interval comprises using the jetting tool to form one or more perforations that penetrate through the casing. The method further comprises introducing a consolidating fluid through the jetting tool and into one or more subterranean formations surrounding the second interval so as to consolidate at least a portion of the one or more subterranean formations.
[0012] The features and advantages of the present invention will be apparent to those skilled in the art upon reading the following description of specific embodiments with reference to the accompanying drawings.
DRAWINGS
[0013] These drawings illustrate certain aspects of the present invention disclosure and should not be used to limit or define the invention.
[0014] Figure 1 is a cross-sectional, side view of a subterranean formation that is penetrated by a cased well bore, in accordance with exemplary embodiments of the present invention;
[0015] Figure 2 is a cross-sectional, side view of the subterranean formation of Figure 1 after treatment with a sealing composition to form an artificial barrier, in accordance with exemplar}' embodiments of the present invention;
[0016] Figure 3 is a cross-sectional, top view of the treated subterranean formation of Figure 2 taken along line 3-3, in accordance with exemplary embodiments of the present invention;
[0017] Figure 4 is a cross-sectional, side view of the treated subterranean formation of Figure 2 after additional treatment with a consolidating fluid, in accordance with exemplary embodiments of the present invention;
[0018] Figure 5 is a cross-sectional, top view of the treated subterranean formation of Figure 4 taken along line 5-5, in accordance with exemplary embodiments of the present invention; and
[0019] Figure 6 is a cross-sectional, top view of the treated subterranean formation of Figure 4 taken along line 5-5, after an additional fracturing treatment, in accordance with exemplary embodiments of the present invention.
DETAILED DESCRIPTION OF SPECIFIC EMBODIMENTS
[0020] The present disclosure relates to methods of completing wells in subterranean formations, such as in unconsolidated subterranean formations. More particularly, the present disclosure relates to methods of completing wells in unconsolidated subterranean formations for controlling water and particulate production.
I. Exemplary Well Completion
[0021] Turning to the drawings and referring first to Figure 1, a well bore 10 is shown that penetrates a hydrocarbon-bearing zone 12 and a water-bearing zone 14. Even though Figure 1 depicts the well bore 10 as a vertical well bore, the methods of the present invention may be suitable for use in deviated or otherwise formed portions of wells. Moreover, as
those of ordinary skill in the art will appreciate, exemplary embodiments of the present invention are applicable for the treatment of both production and injection wells. In the illustrated embodiment, well bore 10 is lined with casing 16 that is cemented to the subterranean formation by cement 18. Those of ordinary skill in the art will appreciate the circumstances when well bore 10 should or should not be cased and whether such casing should or should not be cemented.
[0022] At least a portion of the hydrocarbon-bearing zone 12 may be an unconsolidated formation that contains loose particulates and/or particulates bonded with insufficient bond strength to withstand forces created by the production of fluids through the formation. Accordingly, when the well is completed and the hydrocarbon-bearing zone 12 is placed into production, these particulates may undesirably migrate out of the formation with the fluids produced by the well. Moreover, as illustrated, the hydrocarbon-bearing zone 12 may be adjacent to a water-bearing zone 14. Due to openings into the well bore 10 by perforations, channels behind the casing 16 resulting from incomplete bonding between the casing 16 and the cement 18, fractures, high-permeability streaks, or a variety of other occurrences (e.g., water coning, water cresting, etc.), undesired water production from the water-bearing zone 14 may also occur when the hydrocarbon-bearing zone 12 is placed into production. Exemplary embodiments of the present invention generally address these issues of particulate and water production through successive treatments of different formation intervals with a sealing composition to form an artificial barrier that prevents water flow and with a consolidating fluid to control particulate production.
[0023] Referring now to Figures 2 and 3, in accordance with exemplary embodiments of the present invention, completion of the well may include identifying the location of the hydrocarbon- water interface 20, perforating a first interval 22 of the well bore 10, and introducing a sealing composition into the portion of the subterranean formation surrounding the first interval 22 so that an artificial barrier 24 to water flow is formed. Those of ordinary skill in the art will appreciate that identification of the hydrocarbon-water interface 20 may include identifying the location of the water-bearing zone 14 so that the location of the hydrocarbon-water interface 20 may be identified. In addition, the location of the waterbearing zone 14 and the location of the hydrocarbon- water interface 20 may be identified
using any suitable technique, including, for example, logging after a well bore is drilled or logging while drilling.
[0024] While Figure 2 depicts the first interval 22 as being above the hydrocarbon- water interface 20, those of ordinary skill in the art will appreciate that the first interval 22 may be at any suitable location for the formation of the artificial barrier 24 to water flow. In certain exemplary embodiments, the artificial barrier 24 may be formed at the hydrocarbon- water interface. In another embodiment, the bottom of the artificial barrier 24 may be located about five feet, about ten feet or even greater above the hydrocarbon-water interface 20, for example, to effectively control water coning or cresting. Moreover, in certain exemplary embodiments, placing the top of the artificial barrier 24 above the hydrocarbon-water interface 20 should prevent the flow of water from the water-bearing zone 14 to the hydrocarbon-bearing zone 12. In certain exemplary embodiments, the artificial barrier 24 may overlap the hydrocarbon water interface 20. Accordingly, the first interval 22 may be located at a distance above (e.g., within about five feet, ten feet or greater) the hydrocarbon- water interface 20. Moreover, the first interval 22 may have any suitable length (L) for the desired treatment. By way of example, the first interval 22 may have a length (L) in the range of from about 1 foot to about 50 feet.
[0025] As previously mentioned, exemplary embodiments of the present invention may include perforating a first interval 22 of the well bore 10. In the illustrated embodiment, perforations 26 may be formed that penetrate through the casing 16 and the cement sheath 18 and into the formation. ■ As will be discussed in more detail below, the portion of the hydrocarbon-bearing zone 12 surrounding the first interval 22 may then be treated through the perforations 26 with a sealing composition to form an artificial barrier 24 to prevent, or at least substantially reduce, the migration of water from the water-bearing zone 14 to the hydrocarbon-bearing zone 12.
[0026] While the first interval 22 may be perforated using any suitable technique, an exemplary embodiment utilizes a jetting tool 28, as illustrated by FIG. 2. Jetting tool 28 may be any suitable assembly for use in subterranean operations through which a fluid may be jetted at high pressures. By way of example, when used to form the perforations 26, the jetting tool 28 should be configured to jet a fluid against the casing 16 and the cement sheath
18 such that perforations 26 may be formed. As illustrated, jetting tool 28 may contain ports 30 for discharging a fluid from the jetting tool 28. In some exemplary embodiments, the ports 30 form discharge jets as a result of a high pressure fluid forced out of relatively small ports. In other exemplary embodiments, fluid jet forming nozzles ma}' be connected within the ports 30. Examples of suitable jetting tools are described in U.S. Pat. Nos. 5,765,642 and 5,499,678, the disclosures of which are incorporated herein by reference. In operation, the jetting tool 28 may be positioned in the well bore 10 adjacent the portion of the well bore 10 to be perforated, such as the first interval 22. As illustrated, the jetting tool 28 may be coupled to a work string 32 (e.g., piping, coiled tubing, etc.) and lowered into the well bore 10 to the desired position. Once trie jetting tool 28 has been so positioned, a fluid may be pumped down through the work string 32, into the jetting tool 28, out through the ports 30, and against the interior surface of the casing 16 causing perforations 26 to be formed through the casing 16 and the cement sheath 18. Those of ordinary skill in the art will appreciate that abrasives (e.g., sand) may be included in the jetted fluid.
[0027] In accordance with exemplary embodiments, a sealing composition may be introduced into the portion of the subterranean formation surrounding the first interval 22 so that an artificial barrier 24 to water flow is formed. In general, the sealing composition may be any suitable composition suitable for forming an artificial barrier (such as artificial barrier 24) to water flow in the treated portion of the subterranean formation such that the flow of water therethrough is eliminated or at least substantially reduced. In certain exemplary embodiments, the sealing composition should form a substantially impenetrable barrier that eliminates, or at least partially reduces, the migration of any fluids between the water-bearing zone 14 and the hydrocarbon-bearing zone 12, or vice versa. By way of example, the sealing composition should be able to penetrate into the formation and form an artificial barrier therein that plugs off pore spaces to water flow. Examples of suitable sealing compositions are described in more detail below.
[0028] Any suitable technique may be used for the delivery of the sealing composition into the portion of the hydrocarbon-bearing zone 12 surrounding the first interval 22. For example, bull heading, coil tubing or jointed pipe (e.g., with straddle packers, jetting tools, etc.), or any other suitable technique may be used. In certain exemplary embodiments, the sealing composition may be injected into the hydrocarbon-
bearing formation 12 by the jetting tool 28 while the jetting tool 28 is still in position in the well bore 10. For example, as illustrated by FIG. 2, the jetting tool 28 may be used for the delivery of the sealing composition into the portion of the hydrocarbon-bearing formation 12 that surrounds the first interval 22. Utilization of jetting tool 28 may reduce the need for equipment, such as packers, to isolate the treated interval (e.g., first interval 22). Alternatively, the sealing composition may be injected through the amulus 42 between the work string 32 and the casing 16. It should be noted that, to reduce the potential for the undesired fracturing of the first interval 22, the sealing composition may be introduced into the hydrocarbon-bearing formation 12 at matrix flow rates. By way of example, the sealing composition may be introduced at a flow rate in the range of from about 0.25 barrels to about 3 barrels per minute, depending, for example, on the length of the first interval 22. However, those of ordinary skill in the art will appreciate that these flow rates are merely exemplary, and the present invention is applicable to flow rates outside these ranges.
[0029] In addition, a sufficient amount of the sealing composition should be introduced such that the sealing composition has the desired penetration into the formation. In accordance with exemplary embodiments, it may be desired for the sealing composition to penetrate deep into the formation so that a sufficient artificial barrier 24 to water flow is fonned. By way of example, a sufficient amount of the sealing composition may be introduced such that it penetrates in the range of from about 5 feet to about 50 feet into the formation. However, as those of ordinary skill in the art will appreciate, the depth of penetration of the sealing composition into the formation will vary, for example, based on the particular application.
[0030] Referring now to Figures 4 and 5, exemplary embodiments of the present invention may comprise perforating a second interval 34 of the well bore 10, and introducing a consolidating fluid into the portion of the subterranean formation surrounding the. second interval 34. In general, the second interval 34 may be located above the first interval 22 so that the artificial barrier 24 prevents, or at least substantially reduces, water flow from the water-bearing formation 14 to the portion of the hydrocarbon bearing zone 12 surrounding the second interval 34. In this manner, the undesired production of water and particulates may be controlled once the well is put on production, in accordance with exemplary embodiments. Moreover, the second interval 34 may have any suitable length (L) for the
desired consolidation and production rate. Those of ordinary skill in the art will appreciate that the (L) of the second interval 34 will vary based on a number of factors, including, for example, costs and the desired production rate.
[0031] As previously mentioned, exemplar}' embodiments of the present invention may include perforating the second interval 34 of the well bore 10. In the illustrated embodiment, perforations 36 may be formed in the second interval 34 that penetrate through the casing 16 and the cement sheath 18 and into the formation. As will be discussed in more detail below, the portion of the hydrocarbon-bearing zone 12 surrounding the second interval 34 may then be treated through the perforations 36 with a consolidating fluid for controlling particulate production. While the second interval 34 may be perforated using any suitable technique, an exemplary embodiment utilizes the jetting tool 28. Exemplary embodiments of the jetting tool 28 are described above with respect to perforating the first interval 22. In operation, the jetting tool 28 may be positioned in the well bore 10 adjacent the portion of the well bore 10 to be perforated, such as the second interval 34. By way of example, the jetting tool 28 may be raised from the first interval 22 to the second interval 34. Once the jetting tool 28 has been so positioned, a fluid may be pumped down through the work string 32, into the jetting tool 28, out through the ports 30, and against the interior surface of the casing 16 causing the perforations 36 to be formed through the casing 16 and the cement sheath 18. Those of ordinary skill in the art will appreciate that abrasives (e.g., sand) may be included in the jetted fluid.
[0032] La accordance with exemplar}' embodiments, a consolidating fluid may be introduced into the portion of the subterranean formation surrounding the second interval 34 to consolidate the treated portion of the formation into a consolidated region 38. In general, the consolidating fluid should be any suitable fluid for enhancing the grain-to-grain (or grain- to-formation) contact between particulates in the treated portion of the subterranean formation so that the particulates are stabilized, locked in place, or at least partially immobilized such that they are resistant to flowing with produced or injected fluids. Accordingly, after treatment with the consolidating fluid, the particulates in the consolidated region 38 should be inhibited from migrating with any subsequently produced or injected fluids. Examples of suitable consolidated fluids are described in more detail below.
[0033] Any suitable technique may be used for the deliver}' of the consolidating fluid into the second interval 34, for example, bull heading, coil tubing or jointed pipe (e.g., with straddle packers, jetting tools, etc.), or any other suitable technique may be used. By way of example, as illustrated by FIG. 4, the jetting tool 28 may be used for the delivery of the consolidating fluid into the portion of the hydrocarbon-bearing zone 12 that surrounds the second interval 34. Utilization of the jetting tool 28 may reduce the need for additional equipment (e.g., packers) to isolate the second interval 34. In addition, utilization of the jetting tool 28 in the performance of these steps also may reduce the number of trips into the well bore 10, which in turn may reduce the time and expense of the well completion. Moreover, use of jetting tool 28 to introduce consolidating fluid may also reduce equipment needed to place the fluid, while reducing horsepower requirements. It should be noted that, to reduce the potential for the undesired fracturing of the second interval 34, the consolidating fluid may be introduced into the hydrocarbon-bearing formation 12 at matrix flow rates. By way of example, the consolidating fluid may be introduced at a flow rate in the range of from about 0.25 barrels to about 3 barrels per minute, depending on, for example, the length of perforated interval. However, those of ordinary skill in the art will appreciate that these flow rates are merely exemplary, and the present invention is applicable to flow rates outside these ranges.
[0034] Additionally, the consolidating fluid should achieve sufficient penetration into the formation for the particular application. As illustrated, the consolidating fluid may be introduced into the near well bore portion of the formation surrounding the second interval 34. For example, consolidation of the near well bore portion of the formation may alleviate potential problems associated with particulate production and thus help to control such undesired particulate production. Those of ordinary skill in the art will understand that the "near well bore portion" of a formation generally refers to the portion of a subterranean formation surrounding a well bore. For example, the "near well bore portion" may refer to the portion of the formation surrounding a well bore and having a depth of penetration of from about 1 to about 3 well bore diameters. However, as those of ordinary skill in the art will appreciate, the depth of penetration of the consolidating fluid into the formation may vary based on the particular application.
[0035] While specific reference is made in the above discussion to treatment of the first interval 22 with the sealing composition followed by treatment of the second interval 34 with the consolidating fluid, it should be appreciated that this invention is not limited to such order of treatment. By way of example, the order of treatment may be reversed in that treatment of the second interval 34 with the consolidating fluid may occur prior to treatment of the first interval 22 with the sealing composition.
[0036] It should be noted that, after placement of the consolidating fluid into the formation, the well bore 10 optionally may be shut in for a period of time. The shutting in of the well bore 10 for a period of time may, inter alia, enhance the coating of the consolidating fluid onto the particulates and minimize the washing away of the consolidating fluid during any later subterranean operations. The necessary shut-in time period is dependent, among other things, on the composition of the consolidating fluid used and the temperature of the formation. Generally, the chosen period of time may be between about 0.5 hours and about 72 hours or longer. Determining the proper period of time to shut in the formation is within the ability of one skilled in the art with the benefit of this disclosure.
[0037] Those of ordinary skill in the art will appreciate that introduction of the consolidating fluid into the portion of the formation surrounding the second interval 34 may result in diminishing the formation's permeability. Reduction in permeability due to the consolidating fluid is based on a variety of factors, including the particular consolidating fluid used, the viscosity of the consolidating fluid, the volume of the consolidating fluid, volume of any after-flush treatment fluid, and the pumpability of the formation. However, in some exemplary embodiments, so that fluids may be produced from, and/or injected through, the consolidated region 38, it may be desired to at least partially restore permeability to the consolidated region 38 after this treatment. In certain exemplary embodiments, a fracturing step may be used to reconnect the well bore 10 with portions of the formation outside the consolidated region 38.
[0038] Referring now to Figure 6, one or more fractures 40 may be created or enhanced through the consolidated region 38 and into the surrounding formation to at least partially restore effective permeability to the consolidated region. As used in this disclosure, the term "enhancing" a fracture refers to the extension or enlargement of a natural or
previously created fracture in the formation. The fracturing step may be accomplished by any suitable methodology. By way of example, a hydraulic-fracturing treatment may be used that includes introducing a fracturing fluid into the consolidated region 38 at a pressure sufficient to create or enhance one or more fractures 40. In certain exemplary embodiments, the fracturing step may utilize the j etting tool 28. By way of example, the j etting tool 28 may be used to initiate one or more fractures 40 in the consolidated region 38 by way of jetting a fluid through the perforations 36 and against the consolidated region 38. A fracturing fluid may also be pumped down through the annulus 42 between the work string 32 and the casing 16 and then into the consolidated region 38 at a pressure sufficient to create or enhance the one or more fractures 40. The fracturing fluid may be pumped down through the annulus 42 concurrently with the jetting of the fluid. One example of a suitable fracturing treatment is CobraMax M Fracturing Service, available from Halliburton Energy Services, Inc. hi certain exemplary embodiments, the fracturing fluid may comprise a viscosified fluid (e.g., a gel or a crosslinked gel). In certain embodiments, the fracturing fluid further may comprise proppant 44 that is deposited in the one or more fractures 40 to generate propped fractures. In certain exemplary embodiments, the proppant 44 majr be coated with a consolidating agent (e.g., a curable resin, a tackifying agent, etc.) so that the coated proppant forms a bondable, permeable mass in the one or more fractures 40, for example, to mitigate proppant flow back when the well is placed into production. By way of example, the proppant may be coated with an Expedite™ resin system, available from Halliburton Energy Services, Inc.
[0039] Alternatively, or in addition to the fracturing treatment, one or more after- flush fluids may be used to at least partially restore permeability to the consolidated region 38, if desired. "When used, the after-flush fluid may be introduced into the consolidated region 38 while the consolidating fluid is still in a flowing state. Among other things, the after-flush fluid generally acts to displace at least a portion of the consolidating fluid from flow paths in the consolidated region 38 and to force the displaced portions of the consolidating fluid further into the formation where it may have negligible impact on subsequent production. However, sufficient amounts of the consolidating fluid should remain in the consolidated region 38 to provide effective stabilization of the particulates therein. Generally, the after-flush fluid may be any fluid that does not undesirably react with the other components used or the subterranean formation. For example, the after-flush fluid
may be an aqueous-based fluid, a non-aqueous based fluid (e.g., kerosene, toluene, diesel, or crude oil), or a gas (e.g., nitrogen or carbon dioxide).
[0040] Optionally, one or more pre-flush fluids may be introduced into the portion of the hydrocarbon-bearing zone 12 surrounding second interval 34. By way of example, the pre-flush fluid may be introduced into the formation to, for example, cleanout undesirable substances (e.g., oil, residue, or debris) from pore spaces in the matrix of the formation and/or to prepare the formation for subsequent placement of the consolidating fluid. In exemplary embodiments, an acidic pre-flush fluid may be used to, for example, dissolve undesirable substances in the formation. Examples of suitable pre-flush fluids include aqueous-based fluid, a non-aqueous based fluid (e.g., kerosene, xylene, toluene, diesel, or crude oil), or a gas (e.g., nitrogen or carbon dioxide). Aqueous-based fluids may comprise fresh water, salt water, brines, sea water, or combinations thereof. Further, one or more surfactants may be present in the pre-flush fluid, e.g., to aid a consolidating fluid in flowing to contact points between adjacent particulates in the formation.
II. Exemplary Sealing Compositions
[0041] hi accordance with exemplary embodiments, a sealing composition may be introduced into a portion of a subterranean formation to form an artificial barrier to water flow. As described above, the artificial barrier typically may be located between the waterbearing zone and the hydrocarbon-bearing zone so as to minimize the undesired production of water from the hydrocarbon-bearing zone, hi general, the sealing composition may be any composition suitable for forming an artificial barrier in the treated portion of the subterranean formation such that the flow of water therethrough is eliminated or at least substantially reduced. Examples of suitable sealing compositions may include tackifying fluids, resin compositions, and gelable compositions. In addition, examples of suitable sealing compositions may include fluids that comprise relative-permeability modifiers. As used in this disclosure, the phrase "relative-permeability modifier" refers to compounds that should reduce a formation's effective permeability to water without a comparable reduction in the formation's effective permeability to hydrocarbons. Those of ordinary skill in the art will appreciate that these sealing compositions are merely exemplary, and the present invention is applicable to other compositions for forming a suitable artificial barrier to the flow of water. Examples of suitable sealing compositions will be described in more detail as follows.
A. Exemplary Tackifying Fluids
[0042] As previously mentioned, an exemplary embodiment of the sealing compositions used in the present invention may comprise a tackifying agent. Suitable tackifying agents are substances that are (or may be activated to become) tacky and thus adhere to unconsolidated particulates in the subterranean formation. In this manner, the tackifying agent may form a barrier in the treated portion of the formation. Suitable tackifying agents may not be significantly tacky when placed into the formation, but may be capable of being "activated" (that is destabilized, coalesced and/or reacted) to transform into a tacky compound at a desirable time. Such activation may occur before, during, or after the introduction of the tackifying fluid into the subterranean formation.
[0043] One type of tackifying agent suitable for use includes a non-aqueous tackifying agent. An example of a suitable non-aqueous tackifying agent comprises polyamides that are liquids or in solution at the temperature of the formation such that they are, by themselves, non-hardening when introduced into the subterranean formation. One exemplary embodiment of a suitable tackifying agent comprises a condensation reaction product that comprises commercially available polyacids and a polyamine. Such 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. An example of a suitable non- aqueous tackifying agent is Sand Wedge Enhancement System, available from Halliburton Energy Sendees, Inc.
[0044] Additional exemplary 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 disclosures of which are incorporated herein by reference.
[0045] Non-aqueous tackifying agents may be either used such that they form a non- hardenitig coating or they may be combined with a multifunctional material capable of reacting with the tackifying compound to form a hardened coating. A "hardened coating" as used in this disclosure means that the reaction of the tackifying compound 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 compound alone with the particulates. In this instance, the tackifying agent may function similarly to a hardenable resin.
[0046] Multifunctional materials suitable for use in the present invention include aldehydes, 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, aldehyde condensates, and silyl-modified polyamide compounds and the like, and combinations thereof. Suitable silyl-modified polyamide compounds that may be used in exemplary embodiments of the present invention include those that are substantially self-hardening compositions 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.
[0047] In some exemplary embodiments, 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 exemplary embodiments, the multifunctional material may be 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 disclosure of which is incorporated herein by reference.
[0048] Solvents suitable for use with the tackifying agents include any solvent that is compatible with the tackifying agent and achieves the desired viscosity effect. The solvents that can be used in exemplary embodiments of the present invention preferably include those having high flash points (e.g., above about 125°F). Examples of solvents suitable for use in exemplary embodiments of the present invention include butylglycidyl ether, dipropylene glycol methyl ether, butyl bottom alcohol, dipropylene glycol dimethyl ether, diethyleneglycol methyl ether, ethyl enegly col 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.
[0049] Another type of tackifying agent suitable for use in an exemplary embodiment of the present invention includes aqueous tackifying agents. As used in this disclosure, the term "aqueous tackifying agent" refers to a tackifying agent that is soluble in water. Examples of suitable aqueous tackifying agents generally comprise charged polymers, that when in an aqueous solvent or solution, enhance the grain-to-grain contact between the individual particulates within the formation (e.g., proppant, gravel particulates, formation particulates, or other particulates), and may help bring about the consolidation of the particulates into a cohesive, flexible, and permeable mass. Examples of aqueous tackifying agents suitable for use in an exemplary embodiment of the present invention include 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 copolymers, methacrylic acid derivative polymers, methacrylic acid homopolymers, methacrylic acid ester homopolymers (such as poly(methyl methacrylate), poly(butyl methacrylate), and poly(2-ethylhexyl methacrylate)), acrylamido-methyl-propane sulfonate polymers, acrylamido-methyl-propane sulfonate derivative polymers, acrylamido-methyl-propane sulfonate copolymers, and acrylic acid/acrylamido-methyl-propane sulfonate copolymers, and combinations thereof. Examples of suitable aqueous tackifying agents are FDP-S706-3 and FDP-S800-05, which are available from Halliburton Energy Services, Inc. Examples of suitable aqueous tackifying agents are
described in U.S. Pat. No. 7,131,491 and U.S. Pat App. Pub. No. 2005/0277554, the disclosures of which are incorporated herein by reference.
[0050] Another example of a suitable aqueous tackifying agent comprises a benzyl coco di-(hydroxyethyl) quaternary amine, p-T-amyl-phenol condensed with formaldehyde, or a copolymer comprising from about 80% to about 100% Ci-30 alkylmethacrylate monomers and from about 0% to about 20% hydropbilic monomers. In some exemplary 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 mixogen-containing groups. Suitable hydrophilic monomers include dialJkyl 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 acrylic acid, hydroxyethyl acrylate, acrylamide, and the like. These copolymers can be made by any suitable emulsion polymerization technique. Examples of suitable tackifying agents are described in U.S. Pat. No. 5,249,627, the disclosure of which is incorporated herein by reference. Methods of producing these copolymers are disclosed in U.S. Pat. No. 4,670,501, the disclosure of which is incorporated herein by reference.
B. Exemplary Resin Compositions
[0051] Another example of a sealing composition that may be used in an exemplary embodiment of the present invention may comprise a resin. Resins suitable for use may include any suitable resin that is capable of forming a hardened, consolidated mass in the treated formation. 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 combinations 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 generally require a time-delayed catalyst or an external catalyst to help activate the polymerization of the resins if the cure temperature is low (e.g., less than 250° F) but will cure under the effect of time and temperature if the formation temperature is above about 2500F5 preferably above about 3000F. 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 exemplary embodiments of the present invention and to determine whether a catalyst is needed to trigger curing. An example of a suitable resin is Sand Trap® Formation Consolidation Service, available from Halliburton Energy Services, Inc.
[0052] 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 600F to about 25O0F, 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 3000F to about 6000F, a furan-based resin may be preferred. For subterranean formations having a BHST ranging from about 2000F to about 4000F, 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.
[0053] Any solvent that is compatible with the chosen resin and achieves the desired viscosity effect may be suitable for use with the resin. Some exemplary solvents are those having high flash points (e.g., about 1250F) 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 formamide, diethyleneglycol methyl ether, ethyleneglycol butyl ether, diethyleneglycol butyl ether, propylene carbonate, methanol, butyl alcohol, d-limonene, fatty acid methyl esters, and combinations thereof. Other suitable 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.
C. Exemplary Gelable Compositions
[0054] An example of sealing compositions that may be used in an exemplary embodiment of the present invention comprises gelable compositions. In general, suitable gelable compositions should cure to form a gel. Gelable compositions suitable for use in exemplary embodiments of the present invention include those compositions that cure to form a semi-solid, immovable, gel-like substance. Prior to curing, the gelable compositions should have low viscosities and be capable of flowing in pipe and into the subterranean formation. The gelable composition may be any gelable liquid composition capable of converting into a gelled substance that substantially plugs the permeability of the formation. Accordingly, once placed into the formation, the gelable composition should form the desired artificial barrier. Examples of suitable gelable compositions include gelable aqueous silicate compositions, crosslinkable aqueous polymer compositions, gelable resins and polymerizable organic monomer compositions. Examples of suitable gelable compositions will be described in more detail as follows.
1. Exemplary Gelable Aqueous Silicate Compositions
[0055] In certain exemplary embodiments, the gelable compositions may comprise a gelable aqueous silicate composition. Suitable gelable aqueous silicate compositions for barrier formation generally comprise aqueous alkali metal silicate solution and a catalyst (e.g., a temperature-activated catalyst) for gelling the aqueous alkali metal silicate solution. An example of a suitable gelable aqueous silicate composition is Injectrol™, which is available from Halliburton Energy Services, Inc. Examples of suitable gelable aqueous silicate compositions are described in U.S. Pat. No. 4,466,831, the disclosure of which is incorporated herein by reference.
[0056] The aqueous alkali metal silicate solution component of the gelable aqueous silicate compositions generally may comprise 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 one or more of sodium silicate, potassium silicate, lithium silicate, rubidium silicate, or cesium silicate. While sodium silicate exists in many forms, the sodium silicate that may be used in the aqueous alkali metal silicate solution may have a Na2OtO-SiO2 weight ratio in the range of from about 1 :2 to about 1 :4. By way of example, the sodium silicate may have a Na2CMo-SiO2 weight ratio in the range of about 1 :3.2. Generally, the alkali metal silicate ma}' be 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.
[0057] 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, gel-like 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 that can be used in the gelable aqueous silicate compositions of exemplary embodiments 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 24O0F); sodium acid pyrophosphate (which is most suitable in the range of from about 6O0F to about 2400F); citric acid (which is most suitable in the range of from about 6O0F to about 1200F); and ethyl acetate (which is most suitable in the range of from about 6O0F to about 1200F). Generally, the temperature-activated catalyst may be present in the gelable aqueous silicate composition in the range of from about 0.1% to about 5% by weight of the gelable aqueous silicate composition.
2. Exemplary Crosslinkable Aqueous Polymer Compositions
[0058] In other exemplary embodiments, the gelable compositions may comprise a crosslinkable aqueous polymer composition. Suitable crosslinkable aqueous polymer compositions for barrier formation generally comprise an aqueous solvent, a crosslinkable polymer, and a crosslinking agent. Such compositions are similar to those used to form gelled treatment fluids, such as fracturing fluids, but, according to the methods of exemplary
embodiments of the present invention, they are not exposed to breakers or de-linkers so they retain their viscous nature over time. Moreover, suitable compositions should generally be resistant to breaking, for example, due to formation temperatures. An example of a suitable crosslinkable polymer composition is H2-Zero™, which is commercially available from Halliburton Energy Services, Lac. Examples of suitable crosslinkable aqueous polymer compositions are described in U.S. Pat. Nos. 5,836,392, 6,192,986, and 6,196,317, the disclosures of which are incorporated herein by reference.
[0059] 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 exemplary embodiments of the present invention or with the subterranean formation.
[0060] Examples of crosslinkable polymers that can be used in the crosslinkable aqueous polymer compositions include carboxylate-containing polymers and acrylamide- containing polymers. Examples of suitable acrylamide-containing polymers include polyacrylamide, partially hydrolyzed polyacrylamide, copolymers of acrylamide and acrylate, copolymers of acrylamide and 2-acrylamido-2-methylpropanesulfonic acid, 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 unit's 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 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 exemplary embodiments of the present invention, the crosslinkable polymer may be 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 exemplary embodiment of the present invention, the crosslinkable polymer may be 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.
[0061] The crosslinkable aqueous polymer compositions of exemplary embodiments of the present invention further comprise a crosslinking agent for crosslinking the crosslinkable polymers to form the desired gelled substance. In some exemplary embodiments, the crosslinking agent may be a molecule or complex containing a reactive transition metal cation. An exemplary crosslinking agent comprises trivalent chromium cations complexed or bonded to anions, atomic oxygen, or water. Examples of suitable crosslinking agents include 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. Organic crosslinkers may also be suitable, in certain exemplary embodiments. Examples of suitable organic crosslinkers include polyalkyleneimines, polyalkylenepolyamines (e.g., polyethyleneimine), chitosan, and mixtures thereof.
[0062] The crosslinking agent should be present in the crosslinkable aqueous polymer compositions of exemplary embodiments of the present invention in an amount sufficient to provide, inter alia, the desired degree of crosslinking. In some exemplary embodiments of the present invention, the crosslinking agent may be present in the crosslinkable aqueous polymer compositions of the present invention in an amount in the range of from about 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.
[0063] Optionally, the crosslinkable aqueous polymer compositions may further comprise a crosslinking delaying agent, such as a polysaccharide crosslinking delaying agent 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, such as after placement into the formation. One of ordinary skill in the art, with the benefit of this disclosure, will be able to determine appropriate amount of the crosslinking delaying agent to include in the crosslinkable aqueous polymer compositions for a desired application.
3. Exemplary Gelable Resin Compositions
[0064] Certain exemplary embodiments of the gelable compositions comprise gelable resin compositions that cure to form flexible gels. Unlike the curable resin compositions described below with respect to the consolidating fluids, which cure into hardened masses, the gelable resin compositions cure into flexible, gelled substances that form resilient gelled substances between the particulates of the treated zone of the unconsolidated formation.
[0065] Generally, the gelable resin compositions useful in accordance with exemplary embodiments of the present invention comprise a curable resin, a solvent, and a catalyst. When certain catalysts, such as polyamides, are used in the curable resin compositions, the compositions typically may form the semi-solid, gelled substances described above. Where the catalyst used may cause the organic resin compositions to form hard, brittle material rather than the 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.
[0066] Examples of gelable resins that can be used in exemplary embodiments of the present invention include organic resins such as polyepoxide resins (e.g., Bisphenol a- epichlorohydrin resins), polyester resins, urea-aldehyde resins, furan resins, urethane resins, and mixtures thereof.
[0067] Any solvent that is compatible with the gelable resin and achieves the desired viscosity effect is suitable for use in exemplary embodiments of the present invention. Examples of solvents that may be used in the gelable resin compositions of the present invention include phenols, formaldehydes, furfuryl alcohols, furfurals, alcohols, ethers such as butyl glycidyl ether and cresyl glycidyl etherphenyl glycidyl ether, and combinations thereof. In some embodiments of the present invention, the solvent comprises butyl lactate. The solvent may be used to reduce the viscosity of the gelable resin composition from about 3 to about 3,000 centipoises ("cP") at 8O0F. Among other things, the solvent acts to provide
flexibility to the cured composition. The solvent may be included in the gelable resin composition in an amount sufficient to provide the desired viscosity effect. Generally, the solvent used is included in the gelable resin composition in amount in the range of from about 5% to about 75% by weight of the curable resin.
[0068] Generally, any catalyst that may be used to cure an organic resin is suitable for use in exemplary embodiments of the present invention. Suitable catalysts include internal and external catalysts. When the catalyst chosen is an amide or a polyamide, generally no flexibilizer additive should be required because, inter alia, such catalysts should cause the gelable resin composition to convert into the desired semi-solid, gelled substance. Other suitable catalysts (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 catalyst used is included in the gelable 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 exemplary embodiments of the present invention, the catalyst used is included in the gelable resin composition in an amount in the range of from about 20% to about 75% by weight of the curable resin.
[0069] As noted above, flexibilizer additives may be used, inter alia, to provide flexibility to the gelled substances formed from the curable resin compositions. Flexibilizer additives may be used where the catalyst chosen would cause the gelable resin composition to cure into a hard and brittle material rather than a desired gelled substance. For example, flexibilizer additives may be used where the catalyst chosen is not an amide or polyamide. Examples of suitable flexibilizer additives include an organic ester, an oxygenated organic solvent, an aromatic solvent, and combinations thereof. Of these, ethers, such as diburyl phthalate, may be used in certain exemplary embodiments. Where used, the flexibilizer additive may be included in the gelable 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.
4. Exemplar}7 Polymerizable Organic Monomer Compositions
[0070] Examples of suitable polymerizable organic monomer compositions for use in the sealing compositions generally comprise an aqueous solvent, a water-soluble polymerizable organic monomer, an oxygen scavenger, and a primary initiator. An example of a suitable polymerizable organic monomer composition is Perm-Seal™, which is available from Halliburton Energy Sendees, Inc. Examples of suitable polymerizable organic monomer compositions are described in U.S. Pat. Nos. 5,358,051 and 5,335,726, the disclosures of which are incorporated herein by reference.
[0071] The aqueous solvent 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.
[0072] A variety of monomers are suitable for use as the water-soluble polymerizable organic monomers in exemplary embodiments of the present invention. Examples of suitable monomers include acrylic acid, methacrylic acid, acrylamide, methacrylamide, 2- methacrylamido-2-methylpropane sulfonic acid, 2-dimethylacrylamide, vinyl sulfonic acid, N,N-dimethylaminoethyhnethacrylate, 2-triethylammoniumethylmethacrylate chloride, N,N- dimethyl-aminopropylmethacryl-arnide, memacrylainidepropyltriemylammonium chloride, N-vinyl pyrrolidone, vinyl-phosphonic acid, and methacryloyloxyethyl trimethylammonium sulfate, and mixtures thereof. In exemplary embodiments, the water-soluble polymerizable organic monomer may be self-crosslinking. Examples of suitable monomers which are self- crosslinking include hydroxyethylacrylate, hydroxymethylacrylate, hydroxyethylmethacrylate, N-hydroxymethylacrylamide, N-hydroxymethyl-methacrylamide, polyethylene glycol acrylate, polyethylene glycol methacrylate, polypropylene gylcol acrylate, polypropylene glycol methacrylate, and mixtures thereof. Of these, hydroxyethylacrylate may be used in certain exemplary embodiments. One example particular of a suitable monomer is hydroxyethylcelhαlose- vinyl phosphoric acid.
[0073] 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 exemplary embodiments of the present invention, the water-soluble polymerizable organic monomer is 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 exemplary embodiment of the present invention, the water-soluble polymerizable organic monomer is 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.
[0074] 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 an exemplary embodiment 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.
[0075] The primary initiator is used, inter alia, to initiate polymerization of the water- soluble polymerizable organic monomer(s) used in an exemplary embodiment of the present invention. Any compound or compounds that 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 present in the polymerizable organic monomer composition. Compounds suitable for use as the primary initiator include 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 exemplary 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). One skilled in the art will recognize that as the polymerization temperature increases, the required level of activator decreases.
[0076] 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 exemplary 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).
[0077] Also optionally, the polymerizable organic monomer compositions of exemplary embodiments of the present invention further may comprise a crosslinking agent for crosslinking the polymerizable organic monomer compositions in the desired gelled substance, hi some exemplary embodiments, the crosslinking agent is a molecule or complex containing a reactive transition metal cation, such as, e.g., trivalent chromium cations complexed or bonded to anions, atomic oxygen, or water. Examples of suitable crosslinking agents include 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.
D. Exemplary Relative-Permeability Modifiers
[0078] As described above, fluids that comprise a relative-permeability modifier may be used as the sealing compositions, in accordance with exemplary embodiments of the present invention. "While the relative-permeability modifier generally may not plug pore spaces within the treated formation to block flow therethrough, the relative-permeability modifier should adsorb onto surfaces within the formation so as to selectively reduce the formation's water permeability. As such, the formation may be treated with the relative- permeability modifier to form an artificial barrier in the treated formation that at least partially reduces the flow of water therethough.
[0079] The relative-permeability modifier should be included in the fluid in an amount sufficient to provide the desired artificial barrier. In one exemplary embodiment, the relative-permeability modifier may be included in the fluid in an amount in the range of from 0.01% to about 10% by weight of the fluid. In another exemplary embodiment, the relative- permeability modifier maybe included in the fluid in an amount in the range of from about 0.1% to about 1 % by weight of the fluid.
[0080] In general, suitable relative-permeability modifiers may be any compound capable of selectively reducing the effective permeability of a formation to water without a comparable reduction of the formation's effective permeability to hydrocarbons. Those of ordinary skill in the art will appreciate that a variety of different water-soluble polymers may be suitable for use as the relative-permeability modifiers. Examples of suitable water-soluble polymers include homo-, co-, and terpolymers of acrylamide, 2-acrylamido-2-methyl propane sulfonic acid, N,N-dimethylacrylamide, vinyl pyrrolidone, dimethylamfnoethyl methacrylate, acrylic acid, dimethylaminopropyhnethacrylamide, vinyl amine, vinyl acetate, trimethylammoniumethyl methacrylate chloride, methacrylamide, hydroxyethyl acrylate, vinyl sulfonic acid, vinyl phosphomc acid, methacrylic acid, vinyl caprolactam, N- vinylformamide, N,N-diallylacetamide, dimethyldiallyl ammonium halide, itaconic acid, styrene sulfonic acid, methacrylamidoethyltrimethyl ammonium halide, quaternary salt derivatives of acrylamide quaternary salt derivatives of acrylic acid, and combinations thereof.
[0081] In addition, water-soluble polymers suitable for use as relative-permeability modifiers also may include hydrophobically modified polymers. As used in this disclosure, the phrase "hydrophobicalfy modified," or "hydrophobic modification," or any variation thereof, refers to the incorporation into the hydrophilic polymer structure of hydrophobic groups, wherein the alkyl chain length is from about 4 to about 22 carbons. While these hydrophobically modified polymers have hydrophobic groups incorporated into the hydrophilic polymer structure, they should remain water-soluble. In some embodiments, a mole ratio of a hydrophilic monomer to the hydrophobic compound in the hydrophobically modified polymer is in the range of from about 99.98:0.02 to about 90:10, wherein the hydrophilic monomer is a calculated amount present in the hydrophilic polymer. In certain embodiments, the hydrophobically modified polymers may comprise a polymer backbone that comprises polar heteroatoms. Generally, the polar heteroatoms present within the polymer backbone of the hydrophobically modified polymers include, but are not limited to, oxygen, nitrogen, sulfur, or phosphorous.
[0082] Exemplary hydrophobically modified polymers may be synthesized utilizing any suitable technique. In one example, the hydrophobically modified polymers may be a reaction product of a hydrophilic polymer and a hydrophobic compound. In another example, the hydrophobically modified polymers may be prepared from a polymerization reaction comprising a hydrophilic monomer and a hydrophobically modified hydrophilic monomer. In general, the hydrophobically modified polymers may be pre-reacted before they are placed into the well bore 10. Alternatively, in certain embodiments, the hydrophobically modified polymers may be prepared by an appropriate in situ reaction. Suitable hydrophobically modified polymers and methods for their preparation are described in more detail in U.S. Pat. Nos. 6,476,169 and 7,117,942, the disclosures of which are incorporated herein by reference. Those of ordinary skill in the art, with the benefit of this disclosure, will be able to determine other suitable methods for the synthesis of suitable hydrophobically modified polymers.
[0083] In certain exemplary embodiments of the present invention, suitable hydrophobically modified polymers may be synthesized by the hydrophobic modification of a hydrophilic polymer. The hydrophilic polymers suitable for forming the hydrophobically modified polymers used in the present invention should be capable of reacting with
hydrophobic compounds. Suitable hydropbilic polymers include, homo-, co-, or terpolymers such as, but not limited to, polyacrylamides, polyvinylamines, poly(vinylamines/vinyl alcohols), alkyl acrylate polymers in general, and combinations thereof. Additional examples of alkyl acrylate polymers include polydimethylaminoethyl methacrylate, polydimethylaminopropyl methacrylamide, poly(acrylamide/dmie1hylarninoethyl methacrylate), poly(methacrylic acid/dimethylaminoethyl methacrylate), poly(2-acrylamido- 2-methyl propane sulfonic acid/dimethylaminoethyl methacrylate), poly(acrylamide/dimethylaminopropyl methacrylamide), P°ly (acrylic acid/dimethylaminopropyl methacrylamide), and poly(methacrylic acid/dimethylaminopropyl methacrylamide). In certain exemplary embodiments, the hydrophilic polymers comprise a polymer backbone and reactive amino groups in the polymer backbone or as pendant groups, the reactive amino groups capable of reacting with hydrophobic compounds. In some exemplary embodiments, the hydrophilic polymers comprise dialkyl amino pendant groups. In some exemplary embodiments, the hydrophilic polymers comprise a dimethyl amino pendant group and a monomer comprising dimethylamϊnoethyl methacrylate or drmethylaminopropyl methacrylamide. In certain exemplary embodiments, the hydrophilic polymers comprise a polymer backbone that comprises polar heteroatoms, wherein the polar heteroatoms present within the polymer backbone of the hydrophilic polymers include oxygen, nitrogen, sulfur, or phosphorous. Suitable hydrophilic polymers that comprise polar heteroatoms within the polymer backbone include homo-, co-, or terpolymers, such as, but not limited to, celluloses, chitosans, polyamides, polyetheramines, polyethyleneimines, polyhydroxyetherarnines, polylysines, polysulfones, gums, starches, and combinations thereof. In one exemplary embodiment, the starch is a cationic starch. A suitable cationic starch may be formed by reacting a starch, such as corn, maize, waxy maize, potato, tapioca, or the like, with the reaction product of epichlorohydrin and trialkylamine.
[0084] The hydrophobic compounds that are capable of reacting with the hydrophilic polymers include alkyl halides, sulfonates, sulfates, organic acids, and organic acid derivatives. Examples of suitable organic acids and derivatives thereof include octenyl succinic acid; dodecenyl succinic acid; and anhydrides, esters, imides, and amides of octenyl succinic acid or dodecenyl succinic acid. In certain exemplary embodiments, the hydrophobic compounds may have an alkyl chain length of from about 4 to about 22 carbons. In another exemplary embodiment, the hydrophobic compounds may have an alkyl chain
length of from about 7 to about 22 carbons. In another exemplary embodiment, the hydrophobic compounds may have an alkyl chain length of from about 12 to about 18 carbons. For example, where the hydrophobic compound is an alkyl halide, the reaction between the hydrophobic compound and hydrophilic polymer may result in the quaternization of at least some of the hydrophilic polymer amino groups with an alkyl halide, wherein the alkyl chain length is from about 4 to about 22 carbons.
[0085] As previously mentioned, in certain exemplary embodiments, suitable hydrophobically modified polymers also may be prepared from a polymerization reaction comprising a hydrophilic monomer and a hydrophobically modified hydrophilic monomer. The hydrophobically modified polymers synthesized from the polymerization reactions may have estimated molecular weights in the range of from about 100,000 to about 10,000,000 and mole ratios of the hydrophilic monomer(s) to the hydrophobically modified hydrophilic monomer(s) in the range of from about 99.98:0.02 to about 90:10.
[0086] A variety of hydrophilic monomers may be used to form the hydrophobically modified polymers useful in the present invention. Examples of suitable hydrophilic monomers include acrylamide, 2-acrylamido-2-methyl propane sulfonic acid, N,N- dimethylacrylamide, vinyl pyrrolidone, dimethylaminoethyl methacrylate, acrylic acid, dimemylaminopropylmethacrylamide, vinyl amine, vinyl acetate, Mmethylamrnoniurnethyl methacrylate chloride, methacrylamide, hydroxyethyl acrylate, vinyl sulfonic acid, vinyl phosphonic acid, methacrylic acid, vinyl caprolactam, N-vinylformamide, N,N- diallylacetamide, dimethyldiallyl ammonium halide, itaconic acid, styrene sulfonic acid, methacrylamidoethyltrimethyl ammonium halide, quaternary salt derivatives of acrylamide, and quaternary salt derivatives of acrylic acid.
[0087] A variety of hydrophobically modified hydrophilic monomers also may be used to form the hydrophobically modified polymers useful in exemplary embodiments of the present invention. Examples of suitable hydrophobically modified hydrophilic monomers include alkyl acrylates, alkyl methacrylates, alkyl acrylamides, alkyl methacrylamides alkyl dimethylammoniumethyl methacrylate halides, and alkyl dimethylammoniumpropyl methacrylamide halides, wherein the alkyl groups have from about 4 to about 22 carbon atoms. In another exemplary embodiment, the alkyl groups have from about 7 to about 22
carbons. In another exemplary embodiment, the alkyl groups have from about 12 to about 18 carbons. In certain exemplary embodiments, the hydrophobically modified hydrophilic monomer comprises octadecyldimethylarnmoniumethyl methacrylate bromide, hexadecyldimethylammoniumethyl methacrylate bromide, hexadecyldimethylammoniumpropyl methacrylamide bromide, 2-ethylhexyl methacrylate, or hexadecyl methacrylamide.
[0088] Suitable hydrophobically modified polymers that may be formed from the above-described reactions include acrylamide/octadecyldimethylammoriiumethyl methacrylate bromide copolymer, dimethylamino ethyl methacrylate/vinyl pyrrolidone/hexadecyldimethylammoniumethyl methacrylate bromide terpolymer, and acrylamide/2-acrylainido-2-methyl propane sulfonic acid/2-ethylhexyl methacrylate terpolymer. Another suitable hydrophobically modified polymer formed from the above- described reaction comprises an amino methacrylate/alkyl amino methacrylate copolymer. A suitable dimethlyaminoethyl memacrylate/alkyl-dimethylammoniumethyl methacrylate copolymer is a dimethylaminoethyl methacrylate/hexadecyl-dimethylammoniumethyl methacrylate copolymer. As previously discussed, these copolymers may be formed by reactions with a variety of alkyl halides. For example, in some exemplary embodiments, the hydrophobically modified polymer may comprise a dimethylaminoethyl methacrylate/hexadecyl-dimethylammoniumethyl methacrylate bromide copolymer.
III. Exemplary Consolidating Fluids
[0089] In accordance with exemplar}' embodiments, a consolidating fluid may be introduced into a portion of a subterranean formation to consolidate the treated portion of the formation. In general, the consolidating fluid may be any fluid suitable for enhancing the grain-to-grain (or grain-to-formation) contact between particulates in the treated portion of the subterranean formation so that the particulates are stabilized, locked in place, or at least partially immobilized such that they are resistant to flowing with any produced or injected fluids. When placed into the formation, the consolidating fluid should inhibit dislodged fines from migrating with any subsequently produced or injected fluids. Examples of suitable consolidating fluids include tackifying fluids, resin compositions, and gelable compositions. Those of ordinary skill in the art will appreciate that these consolidating fluids are merely
exemplary, and the present invention is applicable to other fluids for introduction into the formation to control particulate production.
[0090] As previously mentioned, an exemplary embodiment of the consolidating fluids used in the present invention may comprise a tackifying agent. Suitable tackifying agents are substances that are (or may be activated to become) tacky and, thus, impart a degree of consolidation to unconsolidated particulates in the subterranean formation. In this manner, the particulates may be stabilized, locked in place, or at least partially immobilized such that they are resistant to flowing with fluids that are subsequently produced or injected. Suitable tackifying agents may not be significantly tacky when placed into the formation, but may be capable of being "activated" (that is destabilized, coalesced and/or reacted) to transform into a tacky compound at a desirable time. Such activation may occur before, during, or after the introduction of the tackifying fluid into the subterranean formation. Examples of suitable tackifying agents are described in more detail above with respect to the exemplar}' sealing compositions.
[0091] Another example of a consolidating fluid that may be used in an exemplary embodiment of the present invention may comprise a resin. Resins suitable for use may include any resin that is capable of consolidating the treated formation into a hardened, consolidated mass. Examples of suitable resins are described in more detail above with respect to the exemplary sealing compositions.
[0092] Another example of a consolidating fluid that may be used in an exemplary embodiment of the present invention comprises gelable compositions. In general, suitable gelable compositions should cure to form a gel. Gelable compositions suitable for use in exemplary embodiments of the present invention include those compositions that cure to form a semi-solid, immovable, gel-like substance. Prior to curing, the gelable compositions should have low viscosities and be capable of flowing in pipe and into the subterranean formation. The gelable composition may be 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. As referred to in this disclosure, the term "flexible" refers to a state wherein the treated formation is relatively malleable and elastic and able to withstand substantial pressure cycling without substantial breakdown of
the formation. Thus, the resultant gelled substance 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 treated region. Exemplary gelable compositions are described in more detail above with respect to the exemplary sealing compositions.
[0093] While the invention may be susceptible to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and have been described in detail herein. However, it should be understood that the invention is not intended to be limited to the particular forms disclosed. Rather, the invention is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the invention as defined by the following appended claims.
Claims
1. A method of completing a well, comprising: forming an artificial barrier to water flow, wherein the artificial barrier is located at or above a hydrocarbon-water interface between a water-bearing formation zone and a hydrocarbon-bearing formation zone; and consolidating a portion of the hydrocarbon-bearing formation zone, wherein the artificial barrier is located between the consolidated portion of the hydrocarbon-bearing zone and the water-bearing formation zone.
2. The method of claim 1, wherein a bottom of the artificial barrier is located about ten feet above the hydro carbon- water interface.
3. The method of claim 1, wherein the artificial barrier is a substantially impenetrable barrier for reducing fluid migration between the hydrocarbon-bearing formation zone and the water-bearing formation zone.
4. The method of claim 1, wherein forming the artificial barrier comprises introducing a sealing composition into a subterranean formation so as to form the artificial barrier.
5. The method of claim 4, wherein the sealing composition comprises a fluid selected from the group consisting of a tackifying fluid, a resin composition, a gelable composition, a fluid comprising a relative-permeability modifier, and combinations thereof.
6. The method of claim 4, wherein the sealing composition comprises a nonaqueous tackifying agent selected from the group consisting of a polyamide, a condensation reaction product of one or more polyacids and one or more polyamines, a polyester, a polycarbonate, a poly carbamate, a natural resin, a shellac, and combinations thereof.
7. The method of claim 4, wherein the sealing composition comprises an aqueous tackifying agent selected from the group consisting of an acrylic acid polymer, an acrylic acid ester polymer, an acrylic acid derivative polymer, an acrylic acid homopolymer, an acrylic acid ester homopolymers, a poly(methyl acrylate), a poly (butyl acrylate), a poly(2-ethylhexyl acrylate, an acrylic acid ester copolymer, a methacrylic acid derivative polymer, a methacrylic acid homopolymer, a methacrylic acid ester homopolymer, a poly(methyl methacrylate), a poly(butyl methacrylate), a poly(2-ethylhexyl methacrylate), an acrylamido- methyl-propane sulfonate polymer, an acrylamido-methyl-propane sulfonate derivative polymer, an acrylamido-methyl-propane sulfonate copolymer, an acrylic acid/acrylamido- methyl-propane sulfonate copolymer, a benzyl coco di-(hydroxyethyl) quaternary amine, a p- T-amyl-phenol condensed with formaldehyde, a copolymer comprising from about 80% to about 100% C1-3O alkylmethacrylate monomers and from up to about 20% hydrophilic monomers, and combinations thereof.
8. The method of claim 4, wherein the sealing composition comprises a resin selected from the group consisting of a two-component epoxy based resin, a novolak resin, a polyepoxide resin, a phenol-aldehyde resin, a urea-aldehyde resin, a urethane resins, a phenolic resin, a furan resin, a furan/furfuryl alcohol resin, a phenolic/latex resin, a phenol formaldehyde resin, a polyester resin, a hybrid of a polyester resin, a copolymer of a polyester resin, a polyurethane resin, a hybrid of a polyurethane resin, a copolymer of a polyurethane resin, an acrylate resin, and combinations thereof.
9. The method of claim 4, wherein the sealing composition comprises a gelable composition selected from the group consisting of a gelable aqueous silicate composition, a crosslinkable aqueous polymer composition, a gelable resin composition, a polymerizable organic monomer composition, and combinations thereof.
10. The method of claim 4, wherein the sealing composition comprises an aqueous alkali metal silicate solution and a catalyst.
11. The method of claim 4, wherein the sealing composition comprises an aqueous solvent, a crosslinkable polymer, and a crosslinking agent.
12. The method of claim 4, wherein the sealing composition comprises a gelable resin composition comprising a resin selected from the group consisting of an organic resin, a polyepoxide resin, a polyester resin, a urea-aldehyde resin, a furan resin, a urethane resin, and combinations thereof.
13. The method of claim 12, wherein the gelable resin composition comprises a flexibilizer additive selected from the group consisting of an organic ester, an oxygenated organic solvent, an aromatic solvent, and combinations thereof.
14. The method of claim 4, wherein the sealing composition comprises an aqueous solvent, a water-soluble polymerizable organic monomer, an oxygen scavenger, and a primary initiator.
15. The method of claim 4, wherein the sealing composition comprises a fluid comprising a relative permeability modifier selected from the group consisting of homo-, co-, and terpolymers of acrylamide, 2-acrylamido-2-methyl propane sulfonic acid, N9N- dimethylacrylamide, vinyl pyrrolidone, dimethylaminoethyl methacrylate, acrylic acid, dimethylaminopropylmethacrylamide, vinyl amine, vinyl acetate, trimethylammoniumethyl methacrylate chloride, methacrylamide, hydrόxyethyl acrylate, vinyl sulfonic acid, vinyl phosphonic acid, methacrylic acid, vinyl caprolactam, N-vinylformamide, N3N- diallylacetamide, dimethyldiallyl ammonium halide, itaconic acid, styrene sulfonic acid, methacrylamidoemyltrimethyl ammonium halide, a quaternary salt derivative of acrylamide and a quaternary salt derivative of acrylic acid, and combinations thereof.
16. The method of claim 4, wherein the sealing composition comprises a fluid comprising a hydrophobically modified polymer selected from the group consisting of a a hydrophobically modified polyacrylamide, a hydrophobically modified polyvinylamine, a hydrophobically modified poly(vinylamine/vinyl alcohol), a hydrophobically modified alkyl acrylate polymer, a hydrophobically modified cellulose, a hydrophobically modified chitosan, a hydrophobically modified polyamide, a hydrophobically modified polyetheramine, a hydrophobically modified polyethyleneimine, a hydrophobically modified polyhydroxyetheramine, a hydrophobically modified polylysme, a hydrophobically modified polysulfone, a hydrophobically modified gum, a hydrophobically modified starch, and combinations thereof.
17. The method of claim 1, wherein consolidating the portion of the subterranean formation comprises introducing a consolidating fluid into the portion of the hydrocarbon- bearing formation zone so as to consolidate the portion of the hydrocarbon-bearing formation zone.
18. The method of claim 17, wherein the consolidating fluid comprises a fluid selected from the group consisting of a tackifying fluid, a resin composition, a gelable composition, and combinations thereof.
19. The method of claim 17, wherein the consolidating fluid comprises a nonaqueous tackifying agent selected from the group consisting of a polyamide, a condensation reaction product of one or more polyacids and one or more polyamines, a polyester, a polycarbonate, a polycarbamate, a natural resin, a shellac, and combinations thereof.
20. The method of claim 17, wherein the consolidating fluid comprises an aqueous tackifying agent selected from the group consisting of an acrylic acid polymer, an acrylic acid ester polymer, an acrylic acid derivative polymer, an acrylic acid homopolymer, an acrylic acid ester homopolymers, a poly(methyl acrylate), a poly (butyl acrylate), a poly(2-ethylhexyl acrylate, an acrylic acid ester copolymer, a tnethacrylic acid derivative polymer, a methacrylic acid homopolymer, a methacrylic acid ester homopolymer, a poly(methyl methacrylate), a poly(butyl methacrylate), a poly(2-ethylhexyl methacrylate), an acrylamido- methyl-propane sulfonate polymer, an acrylamido-methyl-propane sulfonate derivative polymer, an acrylamido-methyl-propane sulfonate copolymer, an acrylic acid/acrylamido- methyl-propane sulfonate copolymer, a benzyl coco di-(hydroxyethyl) quaternary amine, a p- T-amyl-phenol condensed with formaldehyde, a copolymer comprising from about 80% to about 100% C1-30 alkylmethacrylate monomers and from up to about 20% hydrophilic monomers, and combinations thereof.
21. The method of claim 17, wherein the consolidating fluid comprises a resin selected from the group consisting of a two-component epoxy based resin, a novolak resin, a polyepoxide resin, a phenol-aldehyde resin, a urea-aldehyde resin, a urethane resin, a phenolic resin, a furan resin, a furan/furfuryl alcohol resin, a phenolic/latex resin, a phenol formaldehyde resin, a polyester resin, a hybrid of a polyester resin, a copolymer of a polyester resin, a polyurethane resin, a hybrid of a polyurethane resin, a copolymer of a polyurethane resin, an acrylate resin, and combinations thereof.
22. The method of claim 17, wherein the consolidating fluid comprises a gelable composition selected from the group consisting of a gelable aqueous silicate composition, a crosslinkable aqueous polymer composition, a gelable resin composition, a polymerizable organic monomer composition, and combinations thereof.
23. The method of claim 17, wherein the consolidating fluid comprises a gelable resin composition comprising a resin selected from the group consisting of an organic resin, a polyepoxide resin, a polyester resin, a urea-aldehyde resin, a furan resin, a urethane resin, and combinations thereof.
.
24. The method of claim 11, wherein the consolidating fluid comprises a flexibilizer additive selected from the group consisting of an organic ester, an oxygenated organic solvent, an aromatic solvent, and combinations thereof.
25. The method of claim 1, wherein consolidating the portion of the subterranean formation comprises consolidating particulates within the hydrocarbon-bearing formation zone so that the particulates are inhibited from migrating with any subsequently produced fluids.
26. A method of completing a well for controlling water and particulate production, the method comprising: identifying a hydrocarbon-water interface between a hydrocarbon-bearing formation zone and a water-bearing formation zone; perforating a first interval of a casing; introducing a sealing composition into one or more subterranean formations surrounding the first interval to form an artificial barrier to water flow, wherein the artificial barrier is located either at or above the hydrocarbon-water interface; perforating a second interval of the casing, wherein the second interval is located above the first interval; and introducing a consolidating fluid into one or more subterranean formations surrounding the second interval so as to consolidate at least a portion of the one or more subterranean formations.
27. The method of claim 26, wherein a bottom of the artificial barrier is located about ten feet above the hydrocarbon- water interface.
28. The method of claim 26, wherein the artificial barrier is a substantially impenetrable barrier for reducing fluid migration between the hydrocarbon-bearing formation zone and the water-bearing formation zone.
29. The method of claim 26, wherein the sealing composition penetrates in the range of from about 5 feet to about 50 feet into the one or more subterranean formations.
30. The method of claim 26, wherein the sealing composition comprises a fluid selected from the group consisting of a tackifying fluid, a resin composition, a gelable composition, a fluid comprising a relative-permeability modifier, and combinations thereof.
31. The method of claim 26, wherein the consolidating fluid comprises a fluid selected from the group consisting of a tackifying fluid, a resin composition, a gelable composition, and combinations thereof.
32. The method of claim 26, wherein the particulates within the consolidated portion of the one or more subterranean formations are inhibited from migrating with any subsequently produced fluids.
33. The method of claim 26, wherein the consolidating fluid is introduced into the one or more subterranean formations prior to the introduction of the sealing composition into the one or more subterranean formations.
34. The method of claim 26, wherein the one or more subterranean formations into which the consolidating fluid is introduced and the one or more subterranean formations into which the sealing composition is introduced are the same or different formations.
35. The method of claim 34, wherein the hydrocarbon-bearing formation zone comprises the one or more subterranean formations into which the consolidating fluid is introduced.
36. The method of claim 26, comprising at least one step selected from the group of creating or enhancing one or more propped fractures through the consolidated portion of the one or more subterranean formations, introducing an after-flush fluid into the consolidated portion of the subterranean formation to at least partially restore effective permeability to the consolidated portion, introducing a pre-flush fluid into the one or more subterranean formations surrounding the second interval prior to the introduction of the consolidating fluid, shutting in the well bore after the step of introducing the consolidating fluid, and combinations thereof.
37. A method of completing a well for controlling water and particulate production, the method comprising: positioning a jetting tool at a first location in a well bore; perforating a first interval of casing at the first location, the perforating comprising using the jetting tool to form one or more perforations that penetrate through the casing; introducing a sealing composition through the jetting tool and into one or more subterranean formations surrounding the first interval to form an artificial barrier to water flow, wherein either the artificial barrier is adjacent to a hydrocarbon-water interface between a hydrocarbon-bearing formation zone and a water-bearing formation zone, or a bottom of the artificial barrier is located no more than about ten feet above the hydrocarbon-water interface; positioning the jetting tool in the well bore at a second location above the first location; perforating a second interval of casing at the second location in the well bore, the perforating comprising using the jetting tool to form one or more perforations that penetrate through the casing; and introducing a consolidating fluid through the jetting tool and into one or more formations surrounding the second interval so as to consolidate at least a portion of the one or more subterranean formations.
38. The method of claim 37, comprising jetting a fluid through the jetting tool and into the consolidated portion of the one or more subterranean formations and pumping a fluid down through an annulus between the casing and a work string coupled to the jetting tool and into the consolidated portion such that one or more propped fractures through the consolidated portion are created or enhanced.
Applications Claiming Priority (2)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US11/706,737 US7934557B2 (en) | 2007-02-15 | 2007-02-15 | Methods of completing wells for controlling water and particulate production |
US11/706,737 | 2007-02-15 |
Publications (1)
Publication Number | Publication Date |
---|---|
WO2008099154A1 true WO2008099154A1 (en) | 2008-08-21 |
Family
ID=39345362
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
PCT/GB2008/000476 WO2008099154A1 (en) | 2007-02-15 | 2008-02-08 | Methods of completing wells for controlling water and particulate production |
Country Status (2)
Country | Link |
---|---|
US (1) | US7934557B2 (en) |
WO (1) | WO2008099154A1 (en) |
Cited By (10)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
WO2009087349A1 (en) * | 2008-01-08 | 2009-07-16 | Halliburton Energy Services, Inc. | Methods for controlling water and particulate production in subterranean wells |
US7934557B2 (en) | 2007-02-15 | 2011-05-03 | Halliburton Energy Services, Inc. | Methods of completing wells for controlling water and particulate production |
CN102250595A (en) * | 2011-05-19 | 2011-11-23 | 中国石油天然气集团公司 | Drilling fluid used for active mud shale drilling |
WO2015016934A1 (en) * | 2013-08-01 | 2015-02-05 | Halliburton Energy Services, Inc. | Resin composition for treatment of a subterranean formation |
CN104449618A (en) * | 2015-01-06 | 2015-03-25 | 西南石油大学 | Temperature-resisting salt-tolerant high-temperature self-cross-linking onsite polymerization water plugging gel |
CN110387222A (en) * | 2019-08-01 | 2019-10-29 | 西南石油大学 | A kind of porous gel sealing agent, preparation method and application |
CN111139042A (en) * | 2018-11-02 | 2020-05-12 | 中国石油化工股份有限公司 | Resin modified polymer fluid loss agent based on degradation and preparation method thereof |
CN111139039A (en) * | 2018-11-02 | 2020-05-12 | 中国石油化工股份有限公司 | Sulfonated phenolic resin graft modified polymer filtrate reducer and preparation method thereof |
WO2020146885A1 (en) * | 2019-01-11 | 2020-07-16 | Saudi Arabian Oil Company | Methods and compositions for controlling excess water production |
EP3420047B1 (en) * | 2016-02-23 | 2023-01-11 | Ecolab USA Inc. | Hydrazide crosslinked polymer emulsions for use in crude oil recovery |
Families Citing this family (85)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US7741251B2 (en) * | 2002-09-06 | 2010-06-22 | Halliburton Energy Services, Inc. | Compositions and methods of stabilizing subterranean formations containing reactive shales |
US8631869B2 (en) | 2003-05-16 | 2014-01-21 | Leopoldo Sierra | Methods useful for controlling fluid loss in subterranean treatments |
US8181703B2 (en) | 2003-05-16 | 2012-05-22 | Halliburton Energy Services, Inc. | Method useful for controlling fluid loss in subterranean formations |
US8091638B2 (en) | 2003-05-16 | 2012-01-10 | Halliburton Energy Services, Inc. | Methods useful for controlling fluid loss in subterranean formations |
US7759292B2 (en) | 2003-05-16 | 2010-07-20 | Halliburton Energy Services, Inc. | Methods and compositions for reducing the production of water and stimulating hydrocarbon production from a subterranean formation |
US8962535B2 (en) | 2003-05-16 | 2015-02-24 | Halliburton Energy Services, Inc. | Methods of diverting chelating agents in subterranean treatments |
US8251141B2 (en) | 2003-05-16 | 2012-08-28 | Halliburton Energy Services, Inc. | Methods useful for controlling fluid loss during sand control operations |
US8278250B2 (en) | 2003-05-16 | 2012-10-02 | Halliburton Energy Services, Inc. | Methods useful for diverting aqueous fluids in subterranean operations |
US7678742B2 (en) | 2006-09-20 | 2010-03-16 | Halliburton Energy Services, Inc. | Drill-in fluids and associated methods |
US7678743B2 (en) | 2006-09-20 | 2010-03-16 | Halliburton Energy Services, Inc. | Drill-in fluids and associated methods |
US7687438B2 (en) | 2006-09-20 | 2010-03-30 | Halliburton Energy Services, Inc. | Drill-in fluids and associated methods |
US20080139411A1 (en) * | 2006-12-07 | 2008-06-12 | Harris Phillip C | Methods of treating subterranean formations using hydrophobically modified polymers and compositions of the same |
US7730950B2 (en) * | 2007-01-19 | 2010-06-08 | Halliburton Energy Services, Inc. | Methods for treating intervals of a subterranean formation having variable permeability |
EA017428B1 (en) * | 2007-08-01 | 2012-12-28 | Эм-Ай ЭлЭлСи | Methods of increasing fracture resistance in low permeability formations |
US20090253594A1 (en) * | 2008-04-04 | 2009-10-08 | Halliburton Energy Services, Inc. | Methods for placement of sealant in subterranean intervals |
US7998910B2 (en) | 2009-02-24 | 2011-08-16 | Halliburton Energy Services, Inc. | Treatment fluids comprising relative permeability modifiers and methods of use |
US8420576B2 (en) | 2009-08-10 | 2013-04-16 | Halliburton Energy Services, Inc. | Hydrophobically and cationically modified relative permeability modifiers and associated methods |
US20110186295A1 (en) * | 2010-01-29 | 2011-08-04 | Kaminsky Robert D | Recovery of Hydrocarbons Using Artificial Topseals |
EP2694616A4 (en) | 2011-04-05 | 2014-09-03 | Montgomery Chemicals Llc | Method and compositions for enhanced oil recovery |
WO2012174370A2 (en) * | 2011-06-17 | 2012-12-20 | M-I L.L.C. | Composition of polybutadiene-based formula for downhole applications |
US9291046B2 (en) * | 2011-07-27 | 2016-03-22 | Schlumberger Technology Corporation | Dual or twin-well completion with wettability alteration for segregated oil and water production |
US9045965B2 (en) | 2012-05-01 | 2015-06-02 | Halliburton Energy Services, Inc. | Biodegradable activators to gel silica sol for blocking permeability |
US10093770B2 (en) | 2012-09-21 | 2018-10-09 | Schlumberger Technology Corporation | Supramolecular initiator for latent cationic epoxy polymerization |
US9938452B2 (en) | 2012-10-24 | 2018-04-10 | Halliburton Energy Services, Inc. | Immobile proppants |
US9133386B2 (en) * | 2012-12-12 | 2015-09-15 | Hallburton Energy Services, Inc. | Viscous settable fluid for lost circulation in subterranean formations |
US9863220B2 (en) | 2013-01-08 | 2018-01-09 | Halliburton Energy Services, Inc. | Hydrophobically modified amine-containing polymers for mitigating scale buildup |
US9404031B2 (en) | 2013-01-08 | 2016-08-02 | Halliburton Energy Services, Inc. | Compositions and methods for controlling particulate migration in a subterranean formation |
MX2015014096A (en) * | 2013-04-05 | 2016-02-18 | Mi Llc | Polymeric compositions for downhole applications. |
US9441151B2 (en) | 2013-05-14 | 2016-09-13 | Halliburton Energy Serives, Inc. | Wellbore servicing materials and methods of making and using same |
AU2013400700B2 (en) | 2013-09-23 | 2016-11-03 | Halliburton Energy Services, Inc. | A solidified, thermally insulating composition |
WO2015057215A1 (en) * | 2013-10-16 | 2015-04-23 | Halliburton Energy Services, Inc. | Compositions providing consolidation and water-control |
US9321954B2 (en) * | 2013-11-06 | 2016-04-26 | Halliburton Energy Services, Inc. | Consolidation compositions for use in subterranean formation operations |
US20150233205A1 (en) * | 2014-02-17 | 2015-08-20 | Sharp-Rock Technologies, Inc. | Pumping Fluid To Seal A Subterranean Fracture |
GB2523750A (en) * | 2014-03-03 | 2015-09-09 | Maersl Olie Og Gas As | Method of sealing a fracture in a wellbore and sealing system |
US9663703B2 (en) | 2014-04-25 | 2017-05-30 | James George Clements | Method and compositions for enhanced oil recovery |
US9862872B2 (en) * | 2014-05-09 | 2018-01-09 | Halliburton Energy Services, Inc. | Stabilizing formation laminae in coal seam wellbores |
MX2016014263A (en) * | 2014-06-27 | 2017-02-06 | Halliburton Energy Services Inc | Reaction products of acrylamide polymers and methods for use thereof as relative permeability modifiers. |
WO2016018239A1 (en) * | 2014-07-28 | 2016-02-04 | Halliburton Energy Services, Inc. | Foamed curable resin fluids |
US9810051B2 (en) | 2014-11-20 | 2017-11-07 | Thru Tubing Solutions, Inc. | Well completion |
WO2016137608A1 (en) | 2015-02-26 | 2016-09-01 | Halliburton Energy Services, Inc. | Sealant composition for use in subterranean formations |
US9869170B2 (en) * | 2015-03-17 | 2018-01-16 | Halliburton Energy Services, Inc. | Methods of controlling water production in horizontal wells with multistage fractures |
CN107429154B (en) * | 2015-09-18 | 2020-11-20 | 亨斯迈石油化学有限责任公司 | Improved poly (vinyl caprolactam) kinetic gas hydrate inhibitors and methods of making the same |
CN106566495B (en) * | 2015-10-12 | 2021-11-09 | 中国石油化工股份有限公司 | Tackifying and cutting-improving agent for oil-based drilling fluid and preparation method and application thereof |
WO2017075112A1 (en) * | 2015-10-26 | 2017-05-04 | Savage James M | Improving hydrocarbon production from a well |
US10472555B2 (en) | 2016-04-08 | 2019-11-12 | Schlumberger Technology Corporation | Polymer gel for water control applications |
CN106800919B (en) * | 2017-01-22 | 2018-10-30 | 中国石油大学(华东) | A kind of water-base drilling fluid and its preparation method and application of protection Thief zone reservoir |
US10619083B2 (en) | 2017-02-03 | 2020-04-14 | Saudi Arabian Oil Company | Nanosilica dispersion lost circulation material (LCM) |
US10407609B2 (en) | 2017-05-02 | 2019-09-10 | Saudi Arabian Oil Company | Chemical plugs for preventing wellbore treatment fluid losses |
US10053613B1 (en) | 2017-05-02 | 2018-08-21 | Saudi Arabian Oil Company | Plugging and sealing subterranean formations |
US10759986B2 (en) | 2017-08-17 | 2020-09-01 | Saudi Arabian Oil Company | Loss circulation material composition having alkaline nanoparticle based dispersion and water soluble hydrolysable ester |
US11015102B2 (en) | 2017-08-17 | 2021-05-25 | Saudi Arabian Oil Company | Loss circulation material composition having alkaline nanoparticle based dispersion, water insoluble hydrolysable polyester, and formaldehyde resin |
US10351755B2 (en) | 2017-08-17 | 2019-07-16 | Saudi Arabian Oil Company | Loss circulation material composition having alkaline nanoparticle based dispersion and water insoluble hydrolysable polyester |
US10683452B2 (en) | 2017-09-11 | 2020-06-16 | Saudi Arabian Oil Company | Nanosilica dispersion for thermally insulating packer fluid |
US10233380B1 (en) | 2017-09-11 | 2019-03-19 | Saudi Arabian Oil Company | Well treatment fluid having an acidic nanoparticle based dispersion and a polyamine |
US10577526B2 (en) | 2017-09-11 | 2020-03-03 | Saudi Arabian Oil Company | Loss circulation material composition having an acidic nanoparticle based dispersion and polyamine |
US11279865B2 (en) | 2017-09-11 | 2022-03-22 | Saudi Arabian Oil Company | Well treatment fluid having an acidic nanoparticle based dispersion, an epoxy resin, and a polyamine |
US10316238B2 (en) | 2017-09-11 | 2019-06-11 | Saudi Arabian Oil Company | Nanosilica dispersion for thermally insulating packer fluid |
US10570699B2 (en) | 2017-11-14 | 2020-02-25 | Saudi Arabian Oil Company | Insulating fluid for thermal insulation |
US20190161668A1 (en) | 2017-11-27 | 2019-05-30 | Saudi Arabian Oil Company | Method and materials to convert a drilling mud into a solid gel based lost circulation material |
US11149181B2 (en) | 2017-11-27 | 2021-10-19 | Saudi Arabian Oil Company | Method and materials to convert a drilling mud into a solid gel based lost circulation material |
EP3752577A1 (en) | 2018-02-15 | 2020-12-23 | Saudi Arabian Oil Company | A method and material for isolating a severe loss zone |
US10745610B2 (en) | 2018-05-17 | 2020-08-18 | Saudi Arabian Oil Company | Method and composition for sealing a subsurface formation |
US10954427B2 (en) | 2018-05-17 | 2021-03-23 | Saudi Arabian Oil Company | Method and composition for sealing a subsurface formation |
US10655049B1 (en) | 2019-02-21 | 2020-05-19 | Saudi Arabian Oil Company | Method and materials to convert a drilling mud into a solid gel based lost circulation material |
US10655050B1 (en) | 2019-02-21 | 2020-05-19 | Saudi Arabian Oil Company | Method and materials to convert a drilling mud into a solid gel based lost circulation material |
US11203710B2 (en) | 2019-02-21 | 2021-12-21 | Saudi Arabian Oil Company | Method and materials to convert a drilling mud into a solid gel based lost circulation material |
US11124691B2 (en) | 2019-02-21 | 2021-09-21 | Saudi Arabian Oil Company | Method and materials to convert a drilling mud into a solid gel based lost circulation material |
WO2021046294A1 (en) | 2019-09-05 | 2021-03-11 | Saudi Arabian Oil Company | Propping open hydraulic fractures |
US11781413B2 (en) | 2020-02-04 | 2023-10-10 | Halliburton Energy Services, Inc. | Downhole acid injection to stimulate formation production |
US11408240B2 (en) | 2020-02-04 | 2022-08-09 | Halliburton Energy Services, Inc. | Downhole acid injection to stimulate formation production |
CN113356788A (en) * | 2020-03-06 | 2021-09-07 | 中国石油化工股份有限公司 | Visual simulation device and method for artificial partition plate of radial well structure |
US11098235B1 (en) | 2020-03-18 | 2021-08-24 | Saudi Arabian Oil Company | Methods of converting drilling fluids into geopolymer cements and use thereof |
US11820708B2 (en) | 2020-03-18 | 2023-11-21 | Saudi Arabian Oil Company | Geopolymer cement slurries, cured geopolymer cement and methods of making and use thereof |
US11066899B1 (en) | 2020-03-18 | 2021-07-20 | Saudi Arabian Oil Company | Methods of sealing a subsurface formation with saudi arabian volcanic ash |
US11820707B2 (en) | 2020-03-18 | 2023-11-21 | Saudi Arabian Oil Company | Geopolymer cement slurries, cured geopolymer cement and methods of making and use thereof |
US11015108B1 (en) | 2020-03-18 | 2021-05-25 | Saudi Arabian Oil Company | Methods of reducing lost circulation in a wellbore using Saudi Arabian volcanic ash |
US10920121B1 (en) | 2020-03-18 | 2021-02-16 | Saudi Arabian Oil Company | Methods of reducing lost circulation in a wellbore using Saudi Arabian volcanic ash |
US11299662B2 (en) | 2020-07-07 | 2022-04-12 | Saudi Arabian Oil Company | Method to use lost circulation material composition comprising alkaline nanoparticle based dispersion and sodium bicarbonate in downhole conditions |
US11802232B2 (en) | 2021-03-10 | 2023-10-31 | Saudi Arabian Oil Company | Polymer-nanofiller hydrogels |
CN115163027A (en) * | 2021-04-02 | 2022-10-11 | 中国石油化工股份有限公司 | Method for treating water coning or ridge entering at bottom of oil well |
US11753574B2 (en) | 2021-07-30 | 2023-09-12 | Saudi Arabian Oil Company | Packer fluid with nanosilica dispersion and sodium bicarbonate for thermal insulation |
US11572761B1 (en) | 2021-12-14 | 2023-02-07 | Saudi Arabian Oil Company | Rigless method for selective zonal isolation in subterranean formations using colloidal silica |
US11708521B2 (en) | 2021-12-14 | 2023-07-25 | Saudi Arabian Oil Company | Rigless method for selective zonal isolation in subterranean formations using polymer gels |
US11718776B2 (en) | 2021-12-16 | 2023-08-08 | Saudi Arabian Oil Company | Method to use loss circulation material composition comprising acidic nanoparticle based dispersion and sodium bicarbonate in downhole conditions |
CN116253986A (en) * | 2023-03-31 | 2023-06-13 | 浙江理工大学 | Preparation method of water-based efficient biomass antibacterial flame-retardant polyurethane |
Citations (11)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US3865600A (en) * | 1972-03-08 | 1975-02-11 | Fosroc Ag | Soil consolidation |
US4091868A (en) * | 1977-03-07 | 1978-05-30 | Diversified Chemical Corporation | Method of treating oil wells |
US4718491A (en) * | 1985-08-29 | 1988-01-12 | Institut Francais Du Petrole | Process for preventing water inflow in an oil- and/or gas-producing well |
US5150754A (en) * | 1991-05-28 | 1992-09-29 | Mobil Oil Corporation | Aqueous and petroleum gel method for preventing water-influx |
US5379841A (en) * | 1992-04-10 | 1995-01-10 | Hoechst Aktiengesellschaft | Method for reducing or completely stopping the influx of water in boreholes for the extraction of oil and/or hydrocarbon gas |
US6187839B1 (en) * | 1999-03-03 | 2001-02-13 | Halliburton Energy Services, Inc. | Methods of sealing compositions and methods |
US6228812B1 (en) * | 1998-12-10 | 2001-05-08 | Bj Services Company | Compositions and methods for selective modification of subterranean formation permeability |
US6283210B1 (en) * | 1999-09-01 | 2001-09-04 | Halliburton Energy Services, Inc. | Proactive conformance for oil or gas wells |
US20030092578A1 (en) * | 2001-11-15 | 2003-05-15 | Hirasaki George J. | Subterranean formation water permeability reducing methods |
US20040144542A1 (en) * | 2001-05-25 | 2004-07-29 | Luisa Chiappa | Process for reducing the production of water in oil wells |
US6920928B1 (en) * | 1998-03-27 | 2005-07-26 | Schlumberger Technology Corporation | Method for water control |
Family Cites Families (721)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US3123138A (en) | 1964-03-03 | robichaux | ||
US2238671A (en) | 1940-02-09 | 1941-04-15 | Du Pont | Method of treating wells |
US2278838A (en) | 1940-03-11 | 1942-04-07 | Petrolite Corp | Composition of matter and process for preventing water-in-oil type emulsions resulting from acidization of calcareous oil-bearing strata |
US2689244A (en) | 1950-06-23 | 1954-09-14 | Phillips Petroleum Co | Process for production of chitin sulfate |
US2670329A (en) | 1950-08-03 | 1954-02-23 | Phillips Petroleum Co | Drilling muds and methods of using same |
US2703316A (en) | 1951-06-05 | 1955-03-01 | Du Pont | Polymers of high melting lactide |
US3765804A (en) | 1951-08-13 | 1973-10-16 | Brandon O | Apparatus for producing variable high frequency vibrations in a liquid medium |
US2910436A (en) | 1953-10-02 | 1959-10-27 | California Research Corp | Method of treating wells with acid |
US2863832A (en) | 1954-05-14 | 1958-12-09 | California Research Corp | Method of acidizing petroliferous formations |
US2869642A (en) | 1954-09-14 | 1959-01-20 | Texas Co | Method of treating subsurface formations |
US2843573A (en) | 1955-03-21 | 1958-07-15 | Rohm & Haas | New quaternary ammonium compounds in which the nitrogen atom carries an alkoxymethyl group |
US3065247A (en) | 1955-11-23 | 1962-11-20 | Petrolte Corp | Reaction product of epoxidized fatty acid esters of lower alkanols and polyamino compounds |
US2877179A (en) | 1956-03-26 | 1959-03-10 | Cities Service Res & Dev Co | Composition for and method of inhibiting corrosion of metals |
US2819278A (en) | 1956-05-09 | 1958-01-07 | Petrolite Corp | Reaction product of epoxidized glycerides and hydroxylated tertiary monoamines |
US3173484A (en) | 1958-09-02 | 1965-03-16 | Gulf Research Development Co | Fracturing process employing a heterogeneous propping agent |
US3047067A (en) | 1958-09-08 | 1962-07-31 | Jersey Prod Res Co | Sand consolidation method |
US3008898A (en) | 1959-06-26 | 1961-11-14 | Cities Service Res & Dev Co | Method of inhibiting corrosion |
US3070165A (en) | 1959-12-14 | 1962-12-25 | Phillips Petroleum Co | Fracturing formations in wells |
US3052298A (en) | 1960-03-22 | 1962-09-04 | Shell Oil Co | Method and apparatus for cementing wells |
US3258428A (en) | 1960-08-04 | 1966-06-28 | Petrolite Corp | Scale prevention |
US3259578A (en) | 1960-08-04 | 1966-07-05 | Petrolite Corp | Lubricating compositions |
US3251778A (en) | 1960-08-04 | 1966-05-17 | Petrolite Corp | Process of preventing scale |
US3271307A (en) | 1960-08-04 | 1966-09-06 | Petrolite Corp | Oil well treatment |
US3187567A (en) * | 1961-11-16 | 1965-06-08 | Pure Oil Co | Fluid flow indicating method and apparatus for well bores |
US3297086A (en) | 1962-03-30 | 1967-01-10 | Exxon Production Research Co | Sand consolidation method |
US3237690A (en) * | 1962-10-01 | 1966-03-01 | Gulf Research Development Co | Process for forming an impermeable barrier in subsurface formations |
US3215199A (en) | 1963-02-21 | 1965-11-02 | Shell Oil Co | Acidizing oil formations |
US3272650A (en) | 1963-02-21 | 1966-09-13 | Union Carbide Corp | Process for cleaning conduits |
US3199590A (en) | 1963-02-25 | 1965-08-10 | Halliburton Co | Method of consolidating incompetent sands and composition therefor |
US3195635A (en) | 1963-05-23 | 1965-07-20 | Pan American Petroleum Corp | Spacers for fracture props |
US3316965A (en) | 1963-08-05 | 1967-05-02 | Union Oil Co | Material and process for treating subterranean formations |
US3308886A (en) | 1963-12-26 | 1967-03-14 | Halliburton Co | Retrievable bridge plug |
DE1468014A1 (en) | 1964-01-29 | 1969-01-09 | Henkel & Cie Gmbh | Process for the preparation of hydroxyalkyl ethers of galactomannans |
US3297090A (en) | 1964-04-24 | 1967-01-10 | Shell Oil Co | Acidizing oil formations |
US3307630A (en) | 1964-06-12 | 1967-03-07 | Shell Oil Co | Acidizing oil formations |
US3176768A (en) | 1964-07-27 | 1965-04-06 | California Research Corp | Sand consolidation |
US3492147A (en) | 1964-10-22 | 1970-01-27 | Halliburton Co | Method of coating particulate solids with an infusible resin |
US3302719A (en) | 1965-01-25 | 1967-02-07 | Union Oil Co | Method for treating subterranean formations |
US3251415A (en) | 1965-04-01 | 1966-05-17 | Exxon Production Research Co | Acid treating process |
GB1107584A (en) | 1965-04-06 | 1968-03-27 | Pan American Petroleum Corp | Method of treating unconsolidated well formations |
US3329204A (en) | 1965-04-29 | 1967-07-04 | Schlumberger Well Surv Corp | Methods for well completion |
US3404114A (en) | 1965-06-18 | 1968-10-01 | Dow Chemical Co | Method for preparing latexes having improved adhesive properties |
US3434971A (en) | 1965-08-25 | 1969-03-25 | Dow Chemical Co | Composition and method for acidizing wells |
US3366178A (en) | 1965-09-10 | 1968-01-30 | Halliburton Co | Method of fracturing and propping a subterranean formation |
US3375872A (en) | 1965-12-02 | 1968-04-02 | Halliburton Co | Method of plugging or sealing formations with acidic silicic acid solution |
US3455390A (en) | 1965-12-03 | 1969-07-15 | Union Oil Co | Low fluid loss well treating composition and method |
US3308885A (en) | 1965-12-28 | 1967-03-14 | Union Oil Co | Treatment of subsurface hydrocarbon fluid-bearing formations to reduce water production therefrom |
US3364995A (en) | 1966-02-14 | 1968-01-23 | Dow Chemical Co | Hydraulic fracturing fluid-bearing earth formations |
US3347789A (en) | 1966-03-04 | 1967-10-17 | Petrolite Corp | Treatment of oil wells |
US3451818A (en) | 1966-04-19 | 1969-06-24 | Polaroid Corp | Composite rollfilm assembly for use in the diffusion transfer process |
US3394758A (en) * | 1966-07-28 | 1968-07-30 | Exxon Production Research Co | Method for drilling wells with a gas |
US3382924A (en) | 1966-09-06 | 1968-05-14 | Dow Chemical Co | Treatment of earthen formations comprising argillaceous material |
US3404735A (en) | 1966-11-01 | 1968-10-08 | Halliburton Co | Sand control method |
US3415320A (en) | 1967-02-09 | 1968-12-10 | Halliburton Co | Method of treating clay-containing earth formations |
US3336980A (en) | 1967-02-09 | 1967-08-22 | Exxon Production Research Co | Sand control in wells |
US3378074A (en) | 1967-05-25 | 1968-04-16 | Exxon Production Research Co | Method for fracturing subterranean formations |
US3441085A (en) | 1967-09-07 | 1969-04-29 | Exxon Production Research Co | Method for acid treating carbonate formations |
US3478824A (en) | 1968-04-12 | 1969-11-18 | Chevron Res | Sand consolidation process |
US3481403A (en) | 1968-07-26 | 1969-12-02 | Exxon Production Research Co | Method for consolidating formations surrounding boreholes with resin |
US3525398A (en) | 1968-11-19 | 1970-08-25 | Phillips Petroleum Co | Sealing a permeable stratum with resin |
US3489222A (en) | 1968-12-26 | 1970-01-13 | Chevron Res | Method of consolidating earth formations without removing tubing from well |
DE1905834C3 (en) | 1969-02-06 | 1972-11-09 | Basf Ag | Procedure for avoiding dust and caking of salts or fertilizers |
US3592266A (en) | 1969-03-25 | 1971-07-13 | Halliburton Co | Method of fracturing formations in wells |
US3601194A (en) | 1969-07-14 | 1971-08-24 | Union Oil Co | Low fluid loss well-treating composition and method |
US3565176A (en) | 1969-09-08 | 1971-02-23 | Clifford V Wittenwyler | Consolidation of earth formation using epoxy-modified resins |
US3647567A (en) | 1969-11-28 | 1972-03-07 | Celanese Coatings Co | Post-dipping of acidic deposition coatings |
US3647507A (en) | 1970-01-07 | 1972-03-07 | Johnson & Johnson | Resin composition containing a polyacrylic acid-polyacrylamide copolymer and method of using the same to control resin composition |
DE2250552A1 (en) | 1970-01-30 | 1974-04-18 | Gaf Corp | Filmogenic quat ammonium copolymers - use as hair fixatives ,in textile treatments etc |
US3910862A (en) | 1970-01-30 | 1975-10-07 | Gaf Corp | Copolymers of vinyl pyrrolidone containing quarternary ammonium groups |
US3709641A (en) | 1970-08-03 | 1973-01-09 | Union Oil Co | Apparatus for preparing and extruding a gelatinous material |
US3659651A (en) | 1970-08-17 | 1972-05-02 | Exxon Production Research Co | Hydraulic fracturing using reinforced resin pellets |
US4305463A (en) | 1979-10-31 | 1981-12-15 | Oil Trieval Corporation | Oil recovery method and apparatus |
US3689468A (en) | 1970-12-14 | 1972-09-05 | Rohm & Haas | Unsaturated quaternary monomers and polymers |
US3689418A (en) | 1971-01-18 | 1972-09-05 | Monsanto Co | Detergent formulations |
US3769070A (en) | 1971-02-18 | 1973-10-30 | S Schilt | A method of glazing greenware with an ambient epoxy resin curing composition |
US3681287A (en) | 1971-03-03 | 1972-08-01 | Quaker Oats Co | Siliceous materials bound with resin containing organosilane coupling agent |
US3768564A (en) | 1971-04-26 | 1973-10-30 | Halliburton Co | Method of fracture acidizing a well formation |
US3842911A (en) | 1971-04-26 | 1974-10-22 | Halliburton Co | Method of fracture acidizing a well formation |
US3708013A (en) | 1971-05-03 | 1973-01-02 | Mobil Oil Corp | Method and apparatus for obtaining an improved gravel pack |
US3709298A (en) | 1971-05-20 | 1973-01-09 | Shell Oil Co | Sand pack-aided formation sand consolidation |
US3784585A (en) | 1971-10-21 | 1974-01-08 | American Cyanamid Co | Water-degradable resins containing recurring,contiguous,polymerized glycolide units and process for preparing same |
US3741308A (en) | 1971-11-05 | 1973-06-26 | Permeator Corp | Method of consolidating sand formations |
US3754598A (en) | 1971-11-08 | 1973-08-28 | Phillips Petroleum Co | Method for producing a hydrocarbon-containing formation |
US3744566A (en) | 1972-03-16 | 1973-07-10 | Calgon Corp | Secondary oil recovery process |
US3819525A (en) | 1972-08-21 | 1974-06-25 | Avon Prod Inc | Cosmetic cleansing preparation |
US3857444A (en) | 1972-10-06 | 1974-12-31 | Dow Chemical Co | Method for forming a consolidated gravel pack in a subterranean formation |
US3854533A (en) | 1972-12-07 | 1974-12-17 | Dow Chemical Co | Method for forming a consolidated gravel pack in a subterranean formation |
US3912692A (en) | 1973-05-03 | 1975-10-14 | American Cyanamid Co | Process for polymerizing a substantially pure glycolide composition |
US4042032A (en) | 1973-06-07 | 1977-08-16 | Halliburton Company | Methods of consolidating incompetent subterranean formations using aqueous treating solutions |
US3850247A (en) | 1973-08-27 | 1974-11-26 | Halliburton Co | Placing zones of solids in a subterranean fracture |
US3888311A (en) | 1973-10-01 | 1975-06-10 | Exxon Production Research Co | Hydraulic fracturing method |
US3933205A (en) | 1973-10-09 | 1976-01-20 | Othar Meade Kiel | Hydraulic fracturing process using reverse flow |
US4015995A (en) | 1973-11-23 | 1977-04-05 | Chevron Research Company | Method for delaying the setting of an acid-settable liquid in a terrestrial zone |
US4052345A (en) | 1973-12-17 | 1977-10-04 | Basf Wyandotte Corporation | Process for the preparation of polyurethane foams |
US3863709A (en) | 1973-12-20 | 1975-02-04 | Mobil Oil Corp | Method of recovering geothermal energy |
US3861467A (en) | 1973-12-28 | 1975-01-21 | Texaco Inc | Permeable cementing method |
US3955993A (en) | 1973-12-28 | 1976-05-11 | Texaco Inc. | Method and composition for stabilizing incompetent oil-containing formations |
US3948672A (en) | 1973-12-28 | 1976-04-06 | Texaco Inc. | Permeable cement composition and method |
US3902557A (en) | 1974-03-25 | 1975-09-02 | Exxon Production Research Co | Treatment of wells |
US3943060A (en) | 1974-07-26 | 1976-03-09 | Calgon Corporation | Friction reducing |
US4060988A (en) | 1975-04-21 | 1977-12-06 | Texaco Inc. | Process for heating a fluid in a geothermal formation |
US4000781A (en) | 1975-04-24 | 1977-01-04 | Shell Oil Company | Well treating process for consolidating particles with aqueous emulsions of epoxy resin components |
US4299710A (en) | 1975-05-30 | 1981-11-10 | Rohm And Haas Company | Drilling fluid and method |
US4031958A (en) | 1975-06-13 | 1977-06-28 | Union Oil Company Of California | Plugging of water-producing zones in a subterranean formation |
CA1045027A (en) | 1975-09-26 | 1978-12-26 | Walter A. Hedden | Hydraulic fracturing method using sintered bauxite propping agent |
US4052343A (en) | 1975-11-10 | 1977-10-04 | Rohm And Haas Company | Crosslinked, macroreticular poly(dimethylaminoethyl methacrylate) ion-exchange resins and method of preparation by aqueous suspension polymerization using trialkylamine phase extender |
US3983941A (en) | 1975-11-10 | 1976-10-05 | Mobil Oil Corporation | Well completion technique for sand control |
US4070865A (en) | 1976-03-10 | 1978-01-31 | Halliburton Company | Method of consolidating porous formations using vinyl polymer sealer with divinylbenzene crosslinker |
US4018285A (en) | 1976-03-19 | 1977-04-19 | Exxon Production Research Company | Method for controlling fines migrations |
US4008763A (en) | 1976-05-20 | 1977-02-22 | Atlantic Richfield Company | Well treatment method |
US4089437A (en) | 1976-06-18 | 1978-05-16 | The Procter & Gamble Company | Collapsible co-dispensing tubular container |
CA1103008A (en) | 1976-08-13 | 1981-06-16 | Homer C. Mclaughlin | Treatment of clay formations with organic polycationic polymers |
US4366073A (en) | 1976-08-13 | 1982-12-28 | Halliburton Company | Oil well treating method and composition |
US4366072A (en) | 1976-08-13 | 1982-12-28 | Halliburton Company | Oil well treating method and composition |
US4366071A (en) | 1976-08-13 | 1982-12-28 | Halliburton Company | Oil well treating method and composition |
US4374739A (en) | 1976-08-13 | 1983-02-22 | Halliburton Company | Oil well treating method and composition |
US4366074A (en) | 1976-08-13 | 1982-12-28 | Halliburton Company | Oil well treating method and composition |
US4029148A (en) | 1976-09-13 | 1977-06-14 | Atlantic Richfield Company | Well fracturing method |
US4074760A (en) | 1976-11-01 | 1978-02-21 | The Dow Chemical Company | Method for forming a consolidated gravel pack |
US4085801A (en) | 1976-11-05 | 1978-04-25 | Continental Oil Company | Control of incompetent formations with thickened acid-settable resin compositions |
JPS6024122B2 (en) | 1977-01-05 | 1985-06-11 | 三菱化学株式会社 | Method for producing bead-like polymer |
US4085802A (en) | 1977-01-17 | 1978-04-25 | Continental Oil Company | Use of thickened oil for sand control processes |
US4142595A (en) | 1977-03-09 | 1979-03-06 | Standard Oil Company (Indiana) | Shale stabilizing drilling fluid |
US4129183A (en) | 1977-06-30 | 1978-12-12 | Texaco Inc. | Use of organic acid chrome complexes to treat clay containing formations |
US4127173A (en) | 1977-07-28 | 1978-11-28 | Exxon Production Research Company | Method of gravel packing a well |
US4259205A (en) | 1977-10-06 | 1981-03-31 | Halliburton Company | Process involving breaking of aqueous gel of neutral polysaccharide polymer |
US4152274A (en) | 1978-02-09 | 1979-05-01 | Nalco Chemical Company | Method for reducing friction loss in a well fracturing process |
GB1569063A (en) | 1978-05-22 | 1980-06-11 | Shell Int Research | Formation parts around a borehole method for forming channels of high fluid conductivity in |
US4337828A (en) | 1978-06-19 | 1982-07-06 | Magna Corporation | Method of recovering petroleum from a subterranean reservoir incorporating polyepoxide condensates of resinous polyalkylene oxide adducts and polyether polyols |
US4158521A (en) | 1978-06-26 | 1979-06-19 | The Western Company Of North America | Method of stabilizing clay formations |
US4532052A (en) | 1978-09-28 | 1985-07-30 | Halliburton Company | Polymeric well treating method |
US4460627A (en) | 1978-09-28 | 1984-07-17 | Halliburton Company | Polymeric well treating method |
US4228277A (en) | 1979-02-12 | 1980-10-14 | Hercules Incorporated | Modified nonionic cellulose ethers |
US4291766A (en) | 1979-04-09 | 1981-09-29 | Shell Oil Company | Process for consolidating water-wet sands with an epoxy resin-forming solution |
US4247430A (en) | 1979-04-11 | 1981-01-27 | The Dow Chemical Company | Aqueous based slurry and method of forming a consolidated gravel pack |
US4273187A (en) | 1979-07-30 | 1981-06-16 | Texaco Inc. | Petroleum recovery chemical retention prediction technique |
US4443380A (en) | 1979-08-31 | 1984-04-17 | Asahi-Dow Limited | Organic europlum salt phosphor |
US4306981A (en) | 1979-10-05 | 1981-12-22 | Magna Corporation | Method for breaking petroleum emulsions and the like comprising resinous polyalkylene oxide adducts |
US4552670A (en) | 1979-10-15 | 1985-11-12 | Diamond Shamrock Chemicals Company | Amphoteric water-in-oil self-inverting polymer emulsion |
FR2473180A1 (en) | 1980-01-08 | 1981-07-10 | Petroles Cie Francaise | METHOD OF TRACING THE DRILLING MUD BY DETERMINING THE CONCENTRATION OF A SOLUBLE ION |
US4353806A (en) | 1980-04-03 | 1982-10-12 | Exxon Research And Engineering Company | Polymer-microemulsion complexes for the enhanced recovery of oil |
US4336842A (en) | 1981-01-05 | 1982-06-29 | Graham John W | Method of treating wells using resin-coated particles |
US4814096A (en) | 1981-02-06 | 1989-03-21 | The Dow Chemical Company | Enhanced oil recovery process using a hydrophobic associative composition containing a hydrophilic/hydrophobic polymer |
US4399866A (en) | 1981-04-10 | 1983-08-23 | Atlantic Richfield Company | Method for controlling the flow of subterranean water into a selected zone in a permeable subterranean carbonaceous deposit |
US4393939A (en) | 1981-04-20 | 1983-07-19 | Halliburton Services | Clay stabilization during oil and gas well cementing operations |
US4392988A (en) | 1981-05-11 | 1983-07-12 | Ga Technologies Inc. | Method of producing stable alumina |
US4466831A (en) | 1981-05-21 | 1984-08-21 | Halliburton Company | Rapidly dissolvable silicates and methods of using the same |
US4415805A (en) | 1981-06-18 | 1983-11-15 | Dresser Industries, Inc. | Method and apparatus for evaluating multiple stage fracturing or earth formations surrounding a borehole |
US4395340A (en) | 1981-07-14 | 1983-07-26 | Halliburton Company | Enhanced oil recovery methods and systems |
US4401789A (en) | 1981-07-14 | 1983-08-30 | Halliburton Company | Enhanced oil recovery methods and systems |
US4439334A (en) | 1981-07-14 | 1984-03-27 | Halliburton Company | Enhanced oil recovery methods and systems |
US4460052A (en) | 1981-08-10 | 1984-07-17 | Judith Gockel | Prevention of lost circulation of drilling muds |
US4498995A (en) | 1981-08-10 | 1985-02-12 | Judith Gockel | Lost circulation drilling fluid |
US4441556A (en) | 1981-08-17 | 1984-04-10 | Standard Oil Company | Diverter tool and its use |
US4443347A (en) | 1981-12-03 | 1984-04-17 | Baker Oil Tools, Inc. | Proppant charge and method |
US4428427A (en) | 1981-12-03 | 1984-01-31 | Getty Oil Company | Consolidatable gravel pack method |
US4564459A (en) | 1981-12-03 | 1986-01-14 | Baker Oil Tools, Inc. | Proppant charge and method |
US4664819A (en) | 1981-12-03 | 1987-05-12 | Baker Oil Tools, Inc. | Proppant charge and method |
US4494605A (en) | 1981-12-11 | 1985-01-22 | Texaco Inc. | Sand control employing halogenated, oil soluble hydrocarbons |
US4536297A (en) | 1982-01-28 | 1985-08-20 | Halliburton Company | Well drilling and completion fluid composition |
US4440649A (en) | 1982-01-28 | 1984-04-03 | Halliburton Company | Well drilling and completion fluid composition |
US4439489A (en) | 1982-02-16 | 1984-03-27 | Acme Resin Corporation | Particles covered with a cured infusible thermoset film and process for their production |
US4447342A (en) | 1982-04-19 | 1984-05-08 | Halliburton Co. | Method of clay stabilization in enhanced oil recovery |
US4604216A (en) | 1982-10-19 | 1986-08-05 | Phillips Petroleum Company | Drilling fluids |
US4553596A (en) | 1982-10-27 | 1985-11-19 | Santrol Products, Inc. | Well completion technique |
DE3400164A1 (en) | 1983-01-14 | 1984-07-19 | Sandoz-Patent-GmbH, 7850 Lörrach | LIQUID LOSS REDUCING ADDITIVES FOR PUNCHING LIQUIDS |
US5186257A (en) | 1983-01-28 | 1993-02-16 | Phillips Petroleum Company | Polymers useful in the recovery and processing of natural resources |
US4501328A (en) | 1983-03-14 | 1985-02-26 | Mobil Oil Corporation | Method of consolidation of oil bearing sands |
US4499214A (en) | 1983-05-03 | 1985-02-12 | Diachem Industries, Inc. | Method of rapidly dissolving polymers in water |
US4527627A (en) | 1983-07-28 | 1985-07-09 | Santrol Products, Inc. | Method of acidizing propped fractures |
US4493875A (en) | 1983-12-09 | 1985-01-15 | Minnesota Mining And Manufacturing Company | Proppant for well fractures and method of making same |
US4681165A (en) | 1984-03-01 | 1987-07-21 | Dowell Schlumberger Incorporated | Aqueous chemical wash compositions |
US4541489A (en) | 1984-03-19 | 1985-09-17 | Phillips Petroleum Company | Method of removing flow-restricting materials from wells |
US4546012A (en) | 1984-04-26 | 1985-10-08 | Carbomedics, Inc. | Level control for a fluidized bed |
GB8412423D0 (en) | 1984-05-16 | 1984-06-20 | Allied Colloids Ltd | Polymeric compositions |
KR920006865B1 (en) | 1984-05-18 | 1992-08-21 | 워싱톤 유니버시티 테크놀러지 어소우시에이츠 인코오퍼레이티드 | Method and apparatus for coating particles or liquid droplets |
US4554081A (en) | 1984-05-21 | 1985-11-19 | Halliburton Company | High density well drilling, completion and workover brines, fluid loss reducing additives therefor and methods of use |
GB8413716D0 (en) | 1984-05-30 | 1984-07-04 | Allied Colloids Ltd | Aqueous well fluids |
US4888240A (en) | 1984-07-02 | 1989-12-19 | Graham John W | High strength particulates |
US4585064A (en) | 1984-07-02 | 1986-04-29 | Graham John W | High strength particulates |
US4563292A (en) | 1984-08-02 | 1986-01-07 | Halliburton Company | Methods for stabilizing fines contained in subterranean formations |
US4536303A (en) | 1984-08-02 | 1985-08-20 | Halliburton Company | Methods of minimizing fines migration in subterranean formations |
US4627926A (en) | 1984-09-19 | 1986-12-09 | Exxon Research And Engineering Company | Thermally stable borehole fluids |
US4536305A (en) | 1984-09-21 | 1985-08-20 | Halliburton Company | Methods for stabilizing swelling clays or migrating fines in subterranean formations |
US4608139A (en) | 1985-06-21 | 1986-08-26 | Scm Corporation | Electrocoating process using shear stable cationic latex |
US4619776A (en) | 1985-07-02 | 1986-10-28 | Texas United Chemical Corp. | Crosslinked fracturing fluids |
US4992182A (en) | 1985-11-21 | 1991-02-12 | Union Oil Company Of California | Scale removal treatment |
US4730028A (en) | 1986-03-28 | 1988-03-08 | Exxon Research And Engineering Company | Process for preparing hydrophobically associating terpolymers containing sulfonate functionality |
US4665988A (en) | 1986-04-04 | 1987-05-19 | Halliburton Company | Method of preparation of variable permeability fill material for use in subterranean formations |
EP0421980B1 (en) | 1986-04-18 | 1993-08-25 | Hosokawa Micron Corporation | Particulate material treating apparatus |
US4662448A (en) | 1986-04-25 | 1987-05-05 | Atlantic Richfield Company | Well treatment method using sodium silicate to seal formation |
US4959432A (en) | 1986-05-19 | 1990-09-25 | Union Carbide Chemicals And Plastics Company Inc. | Acid viscosifier compositions |
US4669543A (en) | 1986-05-23 | 1987-06-02 | Halliburton Company | Methods and compositions for consolidating solids in subterranean zones |
US4694905A (en) | 1986-05-23 | 1987-09-22 | Acme Resin Corporation | Precured coated particulate material |
US4785884A (en) | 1986-05-23 | 1988-11-22 | Acme Resin Corporation | Consolidation of partially cured resin coated particulate material |
US4693808A (en) | 1986-06-16 | 1987-09-15 | Shell Oil Company | Downflow fluidized catalytic cranking reactor process and apparatus with quick catalyst separation means in the bottom thereof |
US4693639A (en) | 1986-06-25 | 1987-09-15 | Halliburton Company | Clay stabilizing agent preparation and use |
US4649998A (en) | 1986-07-02 | 1987-03-17 | Texaco Inc. | Sand consolidation method employing latex |
US4737295A (en) | 1986-07-21 | 1988-04-12 | Venture Chemicals, Inc. | Organophilic polyphenolic acid adducts |
US4683954A (en) | 1986-09-05 | 1987-08-04 | Halliburton Company | Composition and method of stimulating subterranean formations |
US4733729A (en) | 1986-09-08 | 1988-03-29 | Dowell Schlumberger Incorporated | Matched particle/liquid density well packing technique |
US4828725A (en) | 1986-10-01 | 1989-05-09 | Air Products And Chemicals, Inc. | Completion fluids containing high molecular weight poly(vinylamines) |
US4787453A (en) | 1986-10-30 | 1988-11-29 | Union Oil Company Of California | Permeability stabilization in subterranean formations containing particulate matter |
US4772646A (en) | 1986-11-17 | 1988-09-20 | Halliburton Company | Concentrated hydrophilic polymer suspensions |
FR2618846A2 (en) | 1986-11-25 | 1989-02-03 | Schlumberger Cie Dowell | PROCESS FOR SEALING UNDERGROUND FORMATIONS, PARTICULARLY IN THE OIL DRILLING SECTOR AND CORRESPONDING COMPOSITIONS AND APPLICATIONS |
US4856590A (en) | 1986-11-28 | 1989-08-15 | Mike Caillier | Process for washing through filter media in a production zone with a pre-packed screen and coil tubing |
US4739832A (en) | 1986-12-24 | 1988-04-26 | Mobil Oil Corporation | Method for improving high impulse fracturing |
US4702319A (en) | 1986-12-29 | 1987-10-27 | Exxon Research And Engineering Company | Enhanced oil recovery with hydrophobically associating polymers containing sulfonate functionality |
US4850430A (en) | 1987-02-04 | 1989-07-25 | Dowell Schlumberger Incorporated | Matched particle/liquid density well packing technique |
US4870167A (en) | 1987-03-02 | 1989-09-26 | Hi-Tek Polymers, Inc. | Hydrophobically modified non-ionic polygalactomannan ethers |
US4796701A (en) | 1987-07-30 | 1989-01-10 | Dowell Schlumberger Incorporated | Pyrolytic carbon coating of media improves gravel packing and fracturing capabilities |
US4828726A (en) | 1987-09-11 | 1989-05-09 | Halliburton Company | Stabilizing clayey formations |
US4942186A (en) | 1987-10-23 | 1990-07-17 | Halliburton Company | Continuously forming and transporting consolidatable resin coated particulate materials in aqueous gels |
US4829100A (en) | 1987-10-23 | 1989-05-09 | Halliburton Company | Continuously forming and transporting consolidatable resin coated particulate materials in aqueous gels |
US4800960A (en) | 1987-12-18 | 1989-01-31 | Texaco Inc. | Consolidatable gravel pack method |
US5071934A (en) | 1987-12-21 | 1991-12-10 | Exxon Research And Engineering Company | Cationic hydrophobic monomers and polymers |
US4892147A (en) | 1987-12-28 | 1990-01-09 | Mobil Oil Corporation | Hydraulic fracturing utilizing a refractory proppant |
IT1224421B (en) | 1987-12-29 | 1990-10-04 | Lamberti Flli Spa | MODIFIED GALATTOMANNANS AND REALIVE PREPARATION PROCEDURE |
DE3805116A1 (en) | 1988-02-18 | 1989-08-31 | Hilterhaus Karl Heinz | METHOD FOR PRODUCING ORGANOMINERAL PRODUCTS |
US4941537A (en) | 1988-02-25 | 1990-07-17 | Hi-Tek Polymers, Inc. | Method for reducing the viscosity of aqueous fluid |
US5248665A (en) | 1988-03-14 | 1993-09-28 | Shell Oil Company | Drilling fluids comprising polycyclic polyether polyol |
US4886354A (en) | 1988-05-06 | 1989-12-12 | Conoco Inc. | Method and apparatus for measuring crystal formation |
US4846118A (en) | 1988-06-14 | 1989-07-11 | Brunswick Corporation | Duel fuel pump and oil-fuel mixing valve system |
US4842072A (en) | 1988-07-25 | 1989-06-27 | Texaco Inc. | Sand consolidation methods |
US5030603A (en) | 1988-08-02 | 1991-07-09 | Norton-Alcoa | Lightweight oil and gas well proppants |
NO893150L (en) | 1988-08-15 | 1990-02-16 | Baroid Technology Inc | PROCEDURE FOR DRILLING A DRILL IN EARTH AND DRILL FOR USE IN THE PROCEDURE. |
US4903770A (en) | 1988-09-01 | 1990-02-27 | Texaco Inc. | Sand consolidation methods |
US4842070A (en) | 1988-09-15 | 1989-06-27 | Amoco Corporation | Procedure for improving reservoir sweep efficiency using paraffinic or asphaltic hydrocarbons |
US4848470A (en) | 1988-11-21 | 1989-07-18 | Acme Resin Corporation | Process for removing flow-restricting materials from wells |
US4898750A (en) | 1988-12-05 | 1990-02-06 | Texaco Inc. | Processes for forming and using particles coated with a resin which is resistant to high temperature and high pH aqueous environments |
US4895207A (en) | 1988-12-19 | 1990-01-23 | Texaco, Inc. | Method and fluid for placing resin coated gravel or sand in a producing oil well |
US4969522A (en) | 1988-12-21 | 1990-11-13 | Mobil Oil Corporation | Polymer-coated support and its use as sand pack in enhanced oil recovery |
US4917186A (en) | 1989-02-16 | 1990-04-17 | Phillips Petroleum Company | Altering subterranean formation permeability |
US4875525A (en) | 1989-03-03 | 1989-10-24 | Atlantic Richfield Company | Consolidated proppant pack for producing formations |
DE3907392A1 (en) | 1989-03-08 | 1990-09-13 | Henkel Kgaa | ESTER OF CARBONIC ACIDS, MEDIUM CHAIN LENGTH, AS THE BEST NEEDLE PART OF THE OIL PHASE IN INVERT DRILL RINSE |
US4934456A (en) | 1989-03-29 | 1990-06-19 | Phillips Petroleum Company | Method for altering high temperature subterranean formation permeability |
US4928763A (en) * | 1989-03-31 | 1990-05-29 | Marathon Oil Company | Method of treating a permeable formation |
US4921576A (en) | 1989-04-20 | 1990-05-01 | Mobil Oil Corporation | Method for improving sweep efficiency in CO2 oil recovery |
US4969523A (en) | 1989-06-12 | 1990-11-13 | Dowell Schlumberger Incorporated | Method for gravel packing a well |
US5351754A (en) | 1989-06-21 | 1994-10-04 | N. A. Hardin 1977 Trust | Apparatus and method to cause fatigue failure of subterranean formations |
US5056597A (en) | 1989-07-27 | 1991-10-15 | Chevron Research And Technology Company | Method for improving the steam splits in a multiple steam injection process using multiple steam headers |
US4936385A (en) | 1989-10-30 | 1990-06-26 | Halliburton Company | Method of particulate consolidation |
US4984635A (en) | 1989-11-16 | 1991-01-15 | Mobil Oil Corporation | Thermal barriers for enhanced oil recovery |
US5464060A (en) | 1989-12-27 | 1995-11-07 | Shell Oil Company | Universal fluids for drilling and cementing wells |
US5049743A (en) | 1990-01-17 | 1991-09-17 | Protechnics International, Inc. | Surface located isotope tracer injection apparatus |
US5182051A (en) | 1990-01-17 | 1993-01-26 | Protechnics International, Inc. | Raioactive tracing with particles |
US5002127A (en) * | 1990-02-27 | 1991-03-26 | Halliburton Company | Placement aid for dual injection placement techniques |
US6184311B1 (en) | 1990-03-26 | 2001-02-06 | Courtaulds Coatings (Holdings) Limited | Powder coating composition of semi-crystalline polyester and curing agent |
US5160642A (en) | 1990-05-25 | 1992-11-03 | Petrolite Corporation | Polyimide quaternary salts as clay stabilization agents |
US5067564A (en) * | 1990-10-12 | 1991-11-26 | Marathon Oil Company | Selective placement of a permeability-reducing material to inhibit fluid communication between a near well bore interval and an underlying aquifer |
US5082056A (en) | 1990-10-16 | 1992-01-21 | Marathon Oil Company | In situ reversible crosslinked polymer gel used in hydrocarbon recovery applications |
US5105886A (en) | 1990-10-24 | 1992-04-21 | Mobil Oil Corporation | Method for the control of solids accompanying hydrocarbon production from subterranean formations |
DE69106869T2 (en) | 1990-10-29 | 1995-05-18 | Inst Francais Du Petrole | USE OF GEL-BASED COMPOSITIONS TO REDUCE WATER PRODUCTION IN OIL OR GAS PRODUCTION HOLES. |
US5256651A (en) | 1991-01-22 | 1993-10-26 | Rhone-Poulenc, Inc. | Hydrophilic-hydrophobic derivatives of polygalactomannans containing tertiary amine functionality |
US5128390A (en) | 1991-01-22 | 1992-07-07 | Halliburton Company | Methods of forming consolidatable resin coated particulate materials in aqueous gels |
US5095987A (en) | 1991-01-31 | 1992-03-17 | Halliburton Company | Method of forming and using high density particulate slurries for well completion |
US5099923A (en) | 1991-02-25 | 1992-03-31 | Nalco Chemical Company | Clay stabilizing method for oil and gas well treatment |
US5197544A (en) | 1991-02-28 | 1993-03-30 | Halliburton Company | Method for clay stabilization with quaternary amines |
US5097904A (en) | 1991-02-28 | 1992-03-24 | Halliburton Company | Method for clay stabilization with quaternary amines |
US5146986A (en) | 1991-03-15 | 1992-09-15 | Halliburton Company | Methods of reducing the water permeability of water and oil producing subterranean formations |
US5278203A (en) | 1991-03-21 | 1994-01-11 | Halliburton Company | Method of preparing and improved liquid gelling agent concentrate and suspendable gelling agent |
IT1245383B (en) | 1991-03-28 | 1994-09-20 | Eniricerche Spa | GELIFIABLE WATER COMPOSITION WITH DELAYED GELIFICATION TIME |
US5244042A (en) | 1991-05-07 | 1993-09-14 | Union Oil Company Of California | Lanthanide-crosslinked polymers for subterranean injection |
US5173527A (en) | 1991-05-15 | 1992-12-22 | Forintek Canada Corp. | Fast cure and pre-cure resistant cross-linked phenol-formaldehyde adhesives and methods of making same |
US5208216A (en) | 1991-06-13 | 1993-05-04 | Nalco Chemical Company | Acrylamide terpolymer shale stabilizing additive for low viscosity oil and gas drilling operations |
US5135051A (en) | 1991-06-17 | 1992-08-04 | Facteau David M | Perforation cleaning tool |
US5178218A (en) | 1991-06-19 | 1993-01-12 | Oryx Energy Company | Method of sand consolidation with resin |
CA2062395A1 (en) | 1991-06-21 | 1992-12-22 | Robert H. Friedman | Sand consolidation methods |
US5232961A (en) | 1991-08-19 | 1993-08-03 | Murphey Joseph R | Hardenable resin compositions and methods |
US5256729A (en) | 1991-09-04 | 1993-10-26 | Atlantic Richfield Company | Nitrile derivative for sand control |
US5199491A (en) | 1991-09-04 | 1993-04-06 | Atlantic Richfield Company | Method of using nitrile derivative for sand control |
US5199492A (en) | 1991-09-19 | 1993-04-06 | Texaco Inc. | Sand consolidation methods |
US5424284A (en) | 1991-10-28 | 1995-06-13 | M-I Drilling Fluids Company | Drilling fluid additive and method for inhibiting hydration |
US5908814A (en) | 1991-10-28 | 1999-06-01 | M-I L.L.C. | Drilling fluid additive and method for inhibiting hydration |
US5218038A (en) | 1991-11-14 | 1993-06-08 | Borden, Inc. | Phenolic resin coated proppants with reduced hydraulic fluid interaction |
CA2057750A1 (en) | 1991-12-16 | 1993-06-17 | Tibor Csabai | Process for producing a high strength artificial (cast) stone with high permeability and filter effect |
US5677187A (en) | 1992-01-29 | 1997-10-14 | Anderson, Ii; David K. | Tagging chemical compositions |
US5211234A (en) | 1992-01-30 | 1993-05-18 | Halliburton Company | Horizontal well completion methods |
US5728653A (en) | 1992-01-31 | 1998-03-17 | Institut Francais Du Petrole | Method for inhibiting reactive argillaceous formations and use thereof in a drilling fluid |
FR2686892B1 (en) | 1992-01-31 | 1995-01-13 | Inst Francais Du Petrole | PROCESS FOR INHIBITING REACTIVE CLAY FORMATIONS AND APPLICATION TO A DRILLING FLUID. |
US5249627A (en) | 1992-03-13 | 1993-10-05 | Halliburton Company | Method for stimulating methane production from coal seams |
US5165438A (en) | 1992-05-26 | 1992-11-24 | Facteau David M | Fluidic oscillator |
US5265678A (en) | 1992-06-10 | 1993-11-30 | Halliburton Company | Method for creating multiple radial fractures surrounding a wellbore |
US5238068A (en) | 1992-07-01 | 1993-08-24 | Halliburton Company | Methods of fracture acidizing subterranean formations |
US5273115A (en) | 1992-07-13 | 1993-12-28 | Gas Research Institute | Method for refracturing zones in hydrocarbon-producing wells |
US5663123A (en) | 1992-07-15 | 1997-09-02 | Kb Technologies Ltd. | Polymeric earth support fluid compositions and method for their use |
US5293939A (en) | 1992-07-31 | 1994-03-15 | Texaco Chemical Company | Formation treating methods |
US5425994A (en) | 1992-08-04 | 1995-06-20 | Technisand, Inc. | Resin coated particulates comprissing a formaldehyde source-metal compound (FS-MC) complex |
US5244362A (en) | 1992-08-17 | 1993-09-14 | Txam Chemical Pumps, Inc. | Chemical injector system for hydrocarbon wells |
US5249628A (en) | 1992-09-29 | 1993-10-05 | Halliburton Company | Horizontal well completions |
US5361856A (en) | 1992-09-29 | 1994-11-08 | Halliburton Company | Well jetting apparatus and met of modifying a well therewith |
US5325923A (en) | 1992-09-29 | 1994-07-05 | Halliburton Company | Well completions with expandable casing portions |
US5396957A (en) | 1992-09-29 | 1995-03-14 | Halliburton Company | Well completions with expandable casing portions |
US5295542A (en) | 1992-10-05 | 1994-03-22 | Halliburton Company | Well gravel packing methods |
US5320171A (en) | 1992-10-09 | 1994-06-14 | Halliburton Company | Method of preventing gas coning and fingering in a high temperature hydrocarbon bearing formation |
US5321062A (en) | 1992-10-20 | 1994-06-14 | Halliburton Company | Substituted alkoxy benzene and use thereof as wetting aid for polyepoxide resins |
US5271466A (en) | 1992-10-30 | 1993-12-21 | Halliburton Company | Subterranean formation treating with dual delayed crosslinking gelled fluids |
US5420174A (en) | 1992-11-02 | 1995-05-30 | Halliburton Company | Method of producing coated proppants compatible with oxidizing gel breakers |
US5332037A (en) | 1992-11-16 | 1994-07-26 | Atlantic Richfield Company | Squeeze cementing method for wells |
US5316587A (en) | 1993-01-21 | 1994-05-31 | Church & Dwight Co., Inc. | Water soluble blast media containing surfactant |
US5387675A (en) | 1993-03-10 | 1995-02-07 | Rhone-Poulenc Specialty Chemicals Co. | Modified hydrophobic cationic thickening compositions |
CA2119316C (en) | 1993-04-05 | 2006-01-03 | Roger J. Card | Control of particulate flowback in subterranean wells |
US5330005A (en) | 1993-04-05 | 1994-07-19 | Dowell Schlumberger Incorporated | Control of particulate flowback in subterranean wells |
US5360068A (en) | 1993-04-19 | 1994-11-01 | Mobil Oil Corporation | Formation fracturing |
US5377759A (en) | 1993-05-20 | 1995-01-03 | Texaco Inc. | Formation treating methods |
US5422183A (en) | 1993-06-01 | 1995-06-06 | Santrol, Inc. | Composite and reinforced coatings on proppants and particles |
GB9313081D0 (en) * | 1993-06-25 | 1993-08-11 | Pumptech Nv | Selective zonal isolation of oil wells |
US5368102A (en) | 1993-09-09 | 1994-11-29 | Halliburton Company | Consolidatable particulate material and well treatment method |
US5545824A (en) | 1993-09-14 | 1996-08-13 | Ppg Industries, Inc. | Curing composition for acrylic polyol coatings and coating produced therefrom |
US5388648A (en) | 1993-10-08 | 1995-02-14 | Baker Hughes Incorporated | Method and apparatus for sealing the juncture between a vertical well and one or more horizontal wells using deformable sealing means |
US5335726A (en) | 1993-10-22 | 1994-08-09 | Halliburton Company | Water control |
US5358051A (en) | 1993-10-22 | 1994-10-25 | Halliburton Company | Method of water control with hydroxy unsaturated carbonyls |
US5377756A (en) | 1993-10-28 | 1995-01-03 | Mobil Oil Corporation | Method for producing low permeability reservoirs using a single well |
US5423381A (en) | 1993-10-29 | 1995-06-13 | Texaco Inc. | Quick-set formation treating methods |
US5381864A (en) | 1993-11-12 | 1995-01-17 | Halliburton Company | Well treating methods using particulate blends |
US5402846A (en) | 1993-11-15 | 1995-04-04 | Mobil Oil Corporation | Unique method of hydraulic fracturing |
DK0654582T3 (en) | 1993-11-18 | 1999-08-30 | Halliburton Energy Serv Inc | Reduction of precipitation of aluminum compounds by acid treatment of an underground formation |
DE69417015T2 (en) | 1993-11-19 | 1999-07-01 | Clearwater Inc | METHOD FOR TREATING SLATE AND CLAY IN OIL HOLES |
EP0656459B1 (en) | 1993-11-27 | 2001-03-28 | AEA Technology plc | Method for treating oil wells |
US5390741A (en) | 1993-12-21 | 1995-02-21 | Halliburton Company | Remedial treatment methods for coal bed methane wells |
US5393810A (en) | 1993-12-30 | 1995-02-28 | Halliburton Company | Method and composition for breaking crosslinked gels |
US5643460A (en) | 1994-01-14 | 1997-07-01 | Nalco/Exxon Energy Chemicals, L. P. | Method for separating oil from water in petroleum production |
FR2716928B1 (en) | 1994-03-03 | 1996-05-03 | Inst Francais Du Petrole | Water-based process and fluid using hydrophobically modified cellulosic derivatives as a filtrate reducer. |
US5445223A (en) | 1994-03-15 | 1995-08-29 | Dowell, A Division Of Schlumberger Technology Corporation | Delayed borate crosslinked fracturing fluid having increased temperature range |
FR2719600B1 (en) | 1994-05-04 | 1996-06-14 | Inst Francais Du Petrole | Process and fluid used in a well - Application to drilling. |
FR2719601B1 (en) | 1994-05-04 | 1996-06-28 | Inst Francais Du Petrole | Water-based process and fluid for controlling the dispersion of solids. Application to drilling. |
US5837656A (en) | 1994-07-21 | 1998-11-17 | Santrol, Inc. | Well treatment fluid compatible self-consolidating particles |
US5494178A (en) | 1994-07-25 | 1996-02-27 | Alu Inc. | Display and decorative fixture apparatus |
US5531274A (en) | 1994-07-29 | 1996-07-02 | Bienvenu, Jr.; Raymond L. | Lightweight proppants and their use in hydraulic fracturing |
US5681796A (en) | 1994-07-29 | 1997-10-28 | Schlumberger Technology Corporation | Borate crosslinked fracturing fluid and method |
US5499678A (en) | 1994-08-02 | 1996-03-19 | Halliburton Company | Coplanar angular jetting head for well perforating |
US5566760A (en) | 1994-09-02 | 1996-10-22 | Halliburton Company | Method of using a foamed fracturing fluid |
US5646093A (en) | 1994-09-13 | 1997-07-08 | Rhone-Poulenc Inc. | Modified polygalactomannans as oil field shale inhibitors |
US5431225A (en) | 1994-09-21 | 1995-07-11 | Halliburton Company | Sand control well completion methods for poorly consolidated formations |
US5498280A (en) | 1994-11-14 | 1996-03-12 | Binney & Smith Inc. | Phosphorescent and fluorescent marking composition |
US5492177A (en) | 1994-12-01 | 1996-02-20 | Mobil Oil Corporation | Method for consolidating a subterranean formation |
GB9426025D0 (en) | 1994-12-22 | 1995-02-22 | Smith Philip L U | Oil and gas field chemicals |
US5551514A (en) | 1995-01-06 | 1996-09-03 | Dowell, A Division Of Schlumberger Technology Corp. | Sand control without requiring a gravel pack screen |
USRE36466E (en) | 1995-01-06 | 1999-12-28 | Dowel | Sand control without requiring a gravel pack screen |
FR2729181A1 (en) | 1995-01-10 | 1996-07-12 | Inst Francais Du Petrole | WATER-BASED PROCESS AND FLUID USING HYDROPHOBICALLY MODIFIED GUARS AS A FILTRATE REDUCER |
US5649323A (en) | 1995-01-17 | 1997-07-15 | Kalb; Paul D. | Composition and process for the encapsulation and stabilization of radioactive hazardous and mixed wastes |
US5522460A (en) | 1995-01-30 | 1996-06-04 | Mobil Oil Corporation | Water compatible chemical in situ and sand consolidation with furan resin |
GB9503949D0 (en) | 1995-02-28 | 1995-04-19 | Atomic Energy Authority Uk | Oil well treatment |
DE69611756T2 (en) | 1995-03-01 | 2001-09-13 | Morii Toshihiro | PAINT COMPOSITE WITH LONG-LUMINOUS PROPERTIES AND COLOR OBJECTS WITH LONG-LUMINOUS PROPERTIES |
US5639806A (en) | 1995-03-28 | 1997-06-17 | Borden Chemical, Inc. | Bisphenol-containing resin coating articles and methods of using same |
US6047772A (en) | 1995-03-29 | 2000-04-11 | Halliburton Energy Services, Inc. | Control of particulate flowback in subterranean wells |
US5501274A (en) | 1995-03-29 | 1996-03-26 | Halliburton Company | Control of particulate flowback in subterranean wells |
US5960878A (en) | 1995-03-29 | 1999-10-05 | Halliburton Energy Services, Inc. | Methods of protecting well tubular goods from corrosion |
US5839510A (en) | 1995-03-29 | 1998-11-24 | Halliburton Energy Services, Inc. | Control of particulate flowback in subterranean wells |
US5582249A (en) | 1995-08-02 | 1996-12-10 | Halliburton Company | Control of particulate flowback in subterranean wells |
US5833000A (en) | 1995-03-29 | 1998-11-10 | Halliburton Energy Services, Inc. | Control of particulate flowback in subterranean wells |
US6209643B1 (en) | 1995-03-29 | 2001-04-03 | Halliburton Energy Services, Inc. | Method of controlling particulate flowback in subterranean wells and introducing treatment chemicals |
US5787986A (en) | 1995-03-29 | 1998-08-04 | Halliburton Energy Services, Inc. | Control of particulate flowback in subterranean wells |
US5775425A (en) | 1995-03-29 | 1998-07-07 | Halliburton Energy Services, Inc. | Control of fine particulate flowback in subterranean wells |
US5604184A (en) | 1995-04-10 | 1997-02-18 | Texaco, Inc. | Chemically inert resin coated proppant system for control of proppant flowback in hydraulically fractured wells |
US5529123A (en) | 1995-04-10 | 1996-06-25 | Atlantic Richfield Company | Method for controlling fluid loss from wells into high conductivity earth formations |
US5551513A (en) | 1995-05-12 | 1996-09-03 | Texaco Inc. | Prepacked screen |
GB9510396D0 (en) | 1995-05-23 | 1995-07-19 | Allied Colloids Ltd | Polymers for drilling and reservoir fluids and their use |
IL114001A (en) | 1995-06-02 | 1998-09-24 | Super Disc Filters Ltd | Pulsator device and method |
US5661561A (en) | 1995-06-02 | 1997-08-26 | Accu-Sort Systems, Inc. | Dimensioning system |
DE19627469A1 (en) | 1995-07-12 | 1997-01-16 | Sanyo Chemical Ind Ltd | Epoxy resin crosslinking agent and one-component epoxy resin composition |
US5836391A (en) | 1995-07-25 | 1998-11-17 | Alberta Oil Sands Technology & Research Authority | Wellbore sand control method |
US5595245A (en) | 1995-08-04 | 1997-01-21 | Scott, Iii; George L. | Systems of injecting phenolic resin activator during subsurface fracture stimulation for enhanced oil recovery |
US5929437A (en) | 1995-08-18 | 1999-07-27 | Protechnics International, Inc. | Encapsulated radioactive tracer |
US5588488A (en) | 1995-08-22 | 1996-12-31 | Halliburton Company | Cementing multi-lateral wells |
US5833361A (en) | 1995-09-07 | 1998-11-10 | Funk; James E. | Apparatus for the production of small spherical granules |
US6028113A (en) | 1995-09-27 | 2000-02-22 | Sunburst Chemicals, Inc. | Solid sanitizers and cleaner disinfectants |
US6528157B1 (en) | 1995-11-01 | 2003-03-04 | Borden Chemical, Inc. | Proppants with fiber reinforced resin coatings |
UA67719C2 (en) | 1995-11-08 | 2004-07-15 | Shell Int Research | Deformable well filter and method for its installation |
US5582250A (en) | 1995-11-09 | 1996-12-10 | Dowell, A Division Of Schlumberger Technology Corporation | Overbalanced perforating and fracturing process using low-density, neutrally buoyant proppant |
US5697448A (en) | 1995-11-29 | 1997-12-16 | Johnson; Gordon | Oil well pumping mechanism providing water removal without lifting |
US5620049A (en) | 1995-12-14 | 1997-04-15 | Atlantic Richfield Company | Method for increasing the production of petroleum from a subterranean formation penetrated by a wellbore |
NO965327L (en) | 1995-12-14 | 1997-06-16 | Halliburton Co | Traceable well cement compositions and methods |
US5697440A (en) | 1996-01-04 | 1997-12-16 | Halliburton Energy Services, Inc. | Control of particulate flowback in subterranean wells |
US5692566A (en) | 1996-01-22 | 1997-12-02 | Texaco Inc. | Formation treating method |
US5704426A (en) | 1996-03-20 | 1998-01-06 | Schlumberger Technology Corporation | Zonal isolation method and apparatus |
US5701956A (en) | 1996-04-17 | 1997-12-30 | Halliburton Energy Services, Inc. | Methods and compositions for reducing water production from subterranean formations |
US6162496A (en) | 1996-05-20 | 2000-12-19 | Blue; David | Method of mixing |
US6620857B2 (en) | 1996-07-02 | 2003-09-16 | Ciba Specialty Chemicals Corporation | Process for curing a polymerizable composition |
US5799734A (en) | 1996-07-18 | 1998-09-01 | Halliburton Energy Services, Inc. | Method of forming and using particulate slurries for well completion |
US5806593A (en) | 1996-07-22 | 1998-09-15 | Texaco Inc | Method to increase sand grain coating coverage |
US5864003A (en) | 1996-07-23 | 1999-01-26 | Georgia-Pacific Resins, Inc. | Thermosetting phenolic resin composition |
US5712314A (en) | 1996-08-09 | 1998-01-27 | Texaco Inc. | Formulation for creating a pliable resin plug |
US5977283A (en) | 1996-08-12 | 1999-11-02 | Lear Corporation | Thermosetting adhesive and method of making same |
US5735349A (en) | 1996-08-16 | 1998-04-07 | Bj Services Company | Compositions and methods for modifying the permeability of subterranean formations |
US5960880A (en) | 1996-08-27 | 1999-10-05 | Halliburton Energy Services, Inc. | Unconsolidated formation stimulation with sand filtration |
GB9619418D0 (en) | 1996-09-18 | 1996-10-30 | Urlwin Smith Phillip L | Oil and gas field chemicals |
US6435277B1 (en) | 1996-10-09 | 2002-08-20 | Schlumberger Technology Corporation | Compositions containing aqueous viscosifying surfactants and methods for applying such compositions in subterranean formations |
US5964295A (en) | 1996-10-09 | 1999-10-12 | Schlumberger Technology Corporation, Dowell Division | Methods and compositions for testing subterranean formations |
US5782300A (en) | 1996-11-13 | 1998-07-21 | Schlumberger Technology Corporation | Suspension and porous pack for reduction of particles in subterranean well fluids, and method for treating an underground formation |
US6059034A (en) | 1996-11-27 | 2000-05-09 | Bj Services Company | Formation treatment method using deformable particles |
US7426961B2 (en) | 2002-09-03 | 2008-09-23 | Bj Services Company | Method of treating subterranean formations with porous particulate materials |
US6330916B1 (en) | 1996-11-27 | 2001-12-18 | Bj Services Company | Formation treatment method using deformable particles |
US6749025B1 (en) | 1996-11-27 | 2004-06-15 | Bj Services Company | Lightweight methods and compositions for sand control |
US20050028979A1 (en) | 1996-11-27 | 2005-02-10 | Brannon Harold Dean | Methods and compositions of a storable relatively lightweight proppant slurry for hydraulic fracturing and gravel packing applications |
US6364018B1 (en) | 1996-11-27 | 2002-04-02 | Bj Services Company | Lightweight methods and compositions for well treating |
US5765642A (en) | 1996-12-23 | 1998-06-16 | Halliburton Energy Services, Inc. | Subterranean formation fracturing methods |
AU6639198A (en) | 1997-03-07 | 1998-09-22 | Dsm N.V. | Radiation-curable composition having high cure speed |
US5830987A (en) | 1997-03-11 | 1998-11-03 | Hehr International Inc. | Amino-acrylate polymers and method |
US5791415A (en) | 1997-03-13 | 1998-08-11 | Halliburton Energy Services, Inc. | Stimulating wells in unconsolidated formations |
US5836393A (en) | 1997-03-19 | 1998-11-17 | Johnson; Howard E. | Pulse generator for oil well and method of stimulating the flow of liquid |
GB9706044D0 (en) | 1997-03-24 | 1997-05-14 | Davidson Brett C | Dynamic enhancement of fluid flow rate using pressure and strain pulsing |
US5865936A (en) | 1997-03-28 | 1999-02-02 | National Starch And Chemical Investment Holding Corporation | Rapid curing structural acrylic adhesive |
GB9708484D0 (en) | 1997-04-25 | 1997-06-18 | Merck Sharp & Dohme | Therapeutic agents |
US5960877A (en) | 1997-05-07 | 1999-10-05 | Halliburton Energy Services, Inc. | Polymeric compositions and methods for use in well applications |
US5840784A (en) | 1997-05-07 | 1998-11-24 | Halliburton Energy Services, Inc. | Polymeric compositions and methods for use in low temperature well applications |
US5968879A (en) | 1997-05-12 | 1999-10-19 | Halliburton Energy Services, Inc. | Polymeric well completion and remedial compositions and methods |
US5981447A (en) | 1997-05-28 | 1999-11-09 | Schlumberger Technology Corporation | Method and composition for controlling fluid loss in high permeability hydrocarbon bearing formations |
US6028534A (en) | 1997-06-02 | 2000-02-22 | Schlumberger Technology Corporation | Formation data sensing with deployed remote sensors during well drilling |
US6169058B1 (en) | 1997-06-05 | 2001-01-02 | Bj Services Company | Compositions and methods for hydraulic fracturing |
US5924488A (en) | 1997-06-11 | 1999-07-20 | Halliburton Energy Services, Inc. | Methods of preventing well fracture proppant flow-back |
US6004400A (en) | 1997-07-09 | 1999-12-21 | Phillip W. Bishop | Carbon dioxide cleaning process |
AU736803B2 (en) | 1997-08-06 | 2001-08-02 | Halliburton Energy Services, Inc. | Well treating fluids and methods |
US6070664A (en) | 1998-02-12 | 2000-06-06 | Halliburton Energy Services | Well treating fluids and methods |
US5944106A (en) | 1997-08-06 | 1999-08-31 | Halliburton Energy Services, Inc. | Well treating fluids and methods |
US5921317A (en) | 1997-08-14 | 1999-07-13 | Halliburton Energy Services, Inc. | Coating well proppant with hardenable resin-fiber composites |
US5887653A (en) | 1997-08-15 | 1999-03-30 | Plainsman Technology, Inc. | Method for clay stabilization |
AU738096B2 (en) | 1997-08-15 | 2001-09-06 | Halliburton Energy Services, Inc. | Light weight high temperature well cement compositions and methods |
US5873413A (en) | 1997-08-18 | 1999-02-23 | Halliburton Energy Services, Inc. | Methods of modifying subterranean strata properties |
US6006836A (en) | 1997-08-18 | 1999-12-28 | Halliburton Energy Services, Inc. | Methods of sealing plugs in well bores |
EP0909875A3 (en) | 1997-10-16 | 1999-10-27 | Halliburton Energy Services, Inc. | Method of completing well in unconsolidated subterranean zone |
US6003600A (en) | 1997-10-16 | 1999-12-21 | Halliburton Energy Services, Inc. | Methods of completing wells in unconsolidated subterranean zones |
US6177484B1 (en) | 1997-11-03 | 2001-01-23 | Texaco Inc. | Combination catalyst/coupling agent for furan resin |
US5944105A (en) | 1997-11-11 | 1999-08-31 | Halliburton Energy Services, Inc. | Well stabilization methods |
US6124246A (en) | 1997-11-17 | 2000-09-26 | Halliburton Energy Services, Inc. | High temperature epoxy resin compositions, additives and methods |
US6140446A (en) | 1997-11-18 | 2000-10-31 | Shin-Etsu Chemical Co., Ltd. | Hydrosilylation catalysts and silicone compositions using the same |
US5893383A (en) | 1997-11-25 | 1999-04-13 | Perfclean International | Fluidic Oscillator |
DE19752093C2 (en) | 1997-11-25 | 2000-10-26 | Clariant Gmbh | Water-soluble copolymers based on acrylamide and their use as cementation aids |
US6059036A (en) | 1997-11-26 | 2000-05-09 | Halliburton Energy Services, Inc. | Methods and compositions for sealing subterranean zones |
GB2332224B (en) | 1997-12-13 | 2000-01-19 | Sofitech Nv | Gelling composition for wellbore service fluids |
EP0926310A1 (en) | 1997-12-24 | 1999-06-30 | Shell Internationale Researchmaatschappij B.V. | Apparatus and method for injecting treatment fluids into an underground formation |
US5960784A (en) | 1998-01-26 | 1999-10-05 | Ryan; John Patrick | Barbecue grill with smoke incinerator |
US6109350A (en) | 1998-01-30 | 2000-08-29 | Halliburton Energy Services, Inc. | Method of reducing water produced with hydrocarbons from wells |
EP0933498B1 (en) | 1998-02-03 | 2003-05-28 | Halliburton Energy Services, Inc. | Method of rapidly consolidating particulate materials in wells |
US6070667A (en) | 1998-02-05 | 2000-06-06 | Halliburton Energy Services, Inc. | Lateral wellbore connection |
US6006835A (en) | 1998-02-17 | 1999-12-28 | Halliburton Energy Services, Inc. | Methods for sealing subterranean zones using foamed resin |
US6516885B1 (en) | 1998-02-18 | 2003-02-11 | Lattice Intellectual Property Ltd | Reducing water flow |
GB2335428B (en) | 1998-03-20 | 2001-03-14 | Sofitech Nv | Hydrophobically modified polymers for water control |
US6012524A (en) | 1998-04-14 | 2000-01-11 | Halliburton Energy Services, Inc. | Remedial well bore sealing methods and compositions |
US6315040B1 (en) | 1998-05-01 | 2001-11-13 | Shell Oil Company | Expandable well screen |
EP0955675B1 (en) | 1998-05-07 | 2004-12-15 | Shin-Etsu Chemical Co., Ltd. | Epoxy resin compositions and semiconductor devices encapsulated therewith |
US6162766A (en) | 1998-05-29 | 2000-12-19 | 3M Innovative Properties Company | Encapsulated breakers, compositions and methods of use |
US6458885B1 (en) | 1998-05-29 | 2002-10-01 | Ppg Industries Ohio, Inc. | Fast drying clear coat composition |
US6024170A (en) | 1998-06-03 | 2000-02-15 | Halliburton Energy Services, Inc. | Methods of treating subterranean formation using borate cross-linking compositions |
US6152234A (en) | 1998-06-10 | 2000-11-28 | Atlantic Richfield Company | Method for strengthening a subterranean formation |
US6016870A (en) | 1998-06-11 | 2000-01-25 | Halliburton Energy Services, Inc. | Compositions and methods for consolidating unconsolidated subterranean zones |
US6068055A (en) | 1998-06-30 | 2000-05-30 | Halliburton Energy Services, Inc. | Well sealing compositions and methods |
US6114410A (en) | 1998-07-17 | 2000-09-05 | Technisand, Inc. | Proppant containing bondable particles and removable particles |
US6059035A (en) | 1998-07-20 | 2000-05-09 | Halliburton Energy Services, Inc. | Subterranean zone sealing methods and compositions |
US6582819B2 (en) | 1998-07-22 | 2003-06-24 | Borden Chemical, Inc. | Low density composite proppant, filtration media, gravel packing media, and sports field media, and methods for making and using same |
US6406789B1 (en) | 1998-07-22 | 2002-06-18 | Borden Chemical, Inc. | Composite proppant, composite filtration media and methods for making and using same |
US6242390B1 (en) | 1998-07-31 | 2001-06-05 | Schlumberger Technology Corporation | Cleanup additive |
US6131661A (en) | 1998-08-03 | 2000-10-17 | Tetra Technologies Inc. | Method for removing filtercake |
US6098711A (en) | 1998-08-18 | 2000-08-08 | Halliburton Energy Services, Inc. | Compositions and methods for sealing pipe in well bores |
US6279652B1 (en) | 1998-09-23 | 2001-08-28 | Halliburton Energy Services, Inc. | Heat insulation compositions and methods |
US6124245A (en) | 1998-10-07 | 2000-09-26 | Phillips Petroleum Company | Drilling fluid additive and process therewith |
US6116342A (en) | 1998-10-20 | 2000-09-12 | Halliburton Energy Services, Inc. | Methods of preventing well fracture proppant flow-back |
JP4169171B2 (en) | 1998-11-13 | 2008-10-22 | ヤマハマリン株式会社 | Oil supply control device for 2-cycle engine |
DE19854207A1 (en) | 1998-11-24 | 2000-05-25 | Wacker Chemie Gmbh | Process for the production of fast-curing molded articles bound with phenolic resin |
US6186228B1 (en) | 1998-12-01 | 2001-02-13 | Phillips Petroleum Company | Methods and apparatus for enhancing well production using sonic energy |
US6213209B1 (en) | 1998-12-02 | 2001-04-10 | Halliburton Energy Services, Inc. | Methods of preventing the production of sand with well fluids |
US6607035B1 (en) | 1998-12-04 | 2003-08-19 | Halliburton Energy Services, Inc. | Preventing flow through subterranean zones |
US6176315B1 (en) | 1998-12-04 | 2001-01-23 | Halliburton Energy Services, Inc. | Preventing flow through subterranean zones |
KR100635550B1 (en) | 1998-12-09 | 2006-10-18 | 니폰 가야꾸 가부시끼가이샤 | Hard coating material and film obtained with the same |
US6196317B1 (en) | 1998-12-15 | 2001-03-06 | Halliburton Energy Services, Inc. | Method and compositions for reducing the permeabilities of subterranean zones |
US6189615B1 (en) | 1998-12-15 | 2001-02-20 | Marathon Oil Company | Application of a stabilized polymer gel to an alkaline treatment region for improved hydrocarbon recovery |
US6130286A (en) | 1998-12-18 | 2000-10-10 | Ppg Industries Ohio, Inc. | Fast drying clear coat composition with low volatile organic content |
US6192985B1 (en) | 1998-12-19 | 2001-02-27 | Schlumberger Technology Corporation | Fluids and techniques for maximizing fracture fluid clean-up |
US6291404B2 (en) | 1998-12-28 | 2001-09-18 | Venture Innovations, Inc. | Viscosified aqueous chitosan-containing well drilling and servicing fluids |
US6562762B2 (en) | 1998-12-28 | 2003-05-13 | Venture Chemicals, Inc. | Method of and composition for reducing the loss of fluid during well drilling, completion or workover operations |
US6358889B2 (en) | 1998-12-28 | 2002-03-19 | Venture Innovations, Inc. | Viscosified aqueous chitosan-containing well drilling and servicing fluids |
US6780822B2 (en) | 1998-12-28 | 2004-08-24 | Venture Chemicals, Inc. | Anhydride-modified chitosan, method of preparation thereof, and fluids containing same |
US6656885B2 (en) | 1998-12-28 | 2003-12-02 | Venture Innovations, Inc. | Anhydride-modified chitosan, method of preparation thereof, and fluids containing same |
US20030130133A1 (en) | 1999-01-07 | 2003-07-10 | Vollmer Daniel Patrick | Well treatment fluid |
US6123871A (en) | 1999-01-11 | 2000-09-26 | Carroll; Michael Lee | Photoluminescence polymers, their preparation and uses thereof |
DE19904147C2 (en) | 1999-02-03 | 2001-05-10 | Herbert Huettlin | Device for treating particulate material |
US6328106B1 (en) | 1999-02-04 | 2001-12-11 | Halliburton Energy Services, Inc. | Sealing subterranean zones |
US6271181B1 (en) | 1999-02-04 | 2001-08-07 | Halliburton Energy Services, Inc. | Sealing subterranean zones |
US6136078A (en) | 1999-02-05 | 2000-10-24 | Binney & Smith Inc. | Marking composition and method for marking dark substrates |
US6244344B1 (en) | 1999-02-09 | 2001-06-12 | Halliburton Energy Services, Inc. | Methods and compositions for cementing pipe strings in well bores |
US6599863B1 (en) | 1999-02-18 | 2003-07-29 | Schlumberger Technology Corporation | Fracturing process and composition |
US6234251B1 (en) | 1999-02-22 | 2001-05-22 | Halliburton Energy Services, Inc. | Resilient well cement compositions and methods |
EP1031611B1 (en) | 1999-02-26 | 2004-07-21 | Shin-Etsu Chemical Co., Ltd. | Room temperature fast curable silicone composition |
DE19909231C2 (en) | 1999-03-03 | 2001-04-19 | Clariant Gmbh | Water-soluble copolymers based on AMPS and their use as drilling aids |
KR100305750B1 (en) | 1999-03-10 | 2001-09-24 | 윤덕용 | Manufacturing Method for Anisotropic Conductive Adhesive for Flip Chip Interconnection on an Organic Substrate |
US6209644B1 (en) | 1999-03-29 | 2001-04-03 | Weatherford Lamb, Inc. | Assembly and method for forming a seal in a junction of a multilateral well bore |
US6148911A (en) | 1999-03-30 | 2000-11-21 | Atlantic Richfield Company | Method of treating subterranean gas hydrate formations |
US6281172B1 (en) | 1999-04-07 | 2001-08-28 | Akzo Nobel Nv | Quaternary nitrogen containing amphoteric water soluble polymers and their use in drilling fluids |
US6063738A (en) | 1999-04-19 | 2000-05-16 | Halliburton Energy Services, Inc. | Foamed well cement slurries, additives and methods |
US6209646B1 (en) | 1999-04-21 | 2001-04-03 | Halliburton Energy Services, Inc. | Controlling the release of chemical additives in well treating fluids |
US6538576B1 (en) | 1999-04-23 | 2003-03-25 | Halliburton Energy Services, Inc. | Self-contained downhole sensor and method of placing and interrogating same |
SG93832A1 (en) | 1999-05-07 | 2003-01-21 | Inst Of Microelectronics | Epoxy resin compositions for liquid encapsulation |
US6534449B1 (en) | 1999-05-27 | 2003-03-18 | Schlumberger Technology Corp. | Removal of wellbore residues |
US6283214B1 (en) | 1999-05-27 | 2001-09-04 | Schlumberger Technology Corp. | Optimum perforation design and technique to minimize sand intrusion |
US6237687B1 (en) | 1999-06-09 | 2001-05-29 | Eclipse Packer Company | Method and apparatus for placing a gravel pack in an oil and gas well |
GB2351098B (en) | 1999-06-18 | 2004-02-04 | Sofitech Nv | Water based wellbore fluids |
US6394181B2 (en) | 1999-06-18 | 2002-05-28 | Halliburton Energy Services, Inc. | Self-regulating lift fluid injection tool and method for use of same |
WO2001004164A2 (en) | 1999-07-09 | 2001-01-18 | The Dow Chemical Company | Hydrogenation of unsaturated polymers using divalent diene-containing bis-cyclopentadienyl group iv metal catalysts |
US6187834B1 (en) | 1999-09-08 | 2001-02-13 | Dow Corning Corporation | Radiation curable silicone compositions |
US6253851B1 (en) | 1999-09-20 | 2001-07-03 | Marathon Oil Company | Method of completing a well |
US6214773B1 (en) | 1999-09-29 | 2001-04-10 | Halliburton Energy Services, Inc. | High temperature, low residue well treating fluids and methods |
US6310008B1 (en) | 1999-10-12 | 2001-10-30 | Halliburton Energy Services, Inc. | Cross-linked well treating fluids |
US6279656B1 (en) | 1999-11-03 | 2001-08-28 | Santrol, Inc. | Downhole chemical delivery system for oil and gas wells |
JP4857421B2 (en) | 1999-12-08 | 2012-01-18 | 独立行政法人産業技術総合研究所 | Biodegradable resin composition |
US6311773B1 (en) | 2000-01-28 | 2001-11-06 | Halliburton Energy Services, Inc. | Resin composition and methods of consolidating particulate solids in wells with or without closure pressure |
FR2804953B1 (en) | 2000-02-10 | 2002-07-26 | Inst Francais Du Petrole | CEMENT DAIRY HAVING HYDROPHOBIC POLYMERS |
US6609578B2 (en) | 2000-02-11 | 2003-08-26 | Mo M-I Llc | Shale hydration inhibition agent and method of use |
US6302207B1 (en) | 2000-02-15 | 2001-10-16 | Halliburton Energy Services, Inc. | Methods of completing unconsolidated subterranean producing zones |
US6394184B2 (en) | 2000-02-15 | 2002-05-28 | Exxonmobil Upstream Research Company | Method and apparatus for stimulation of multiple formation intervals |
US6767869B2 (en) | 2000-02-29 | 2004-07-27 | Bj Services Company | Well service fluid and method of making and using the same |
US6257335B1 (en) | 2000-03-02 | 2001-07-10 | Halliburton Energy Services, Inc. | Stimulating fluid production from unconsolidated formations |
AU2001260178B2 (en) | 2000-04-05 | 2005-12-15 | Schlumberger Technology B.V. | Viscosity reduction of viscoelastic surfactant based fluids |
US6745159B1 (en) | 2000-04-28 | 2004-06-01 | Halliburton Energy Services, Inc. | Process of designing screenless completions for oil or gas wells |
GB2382143B (en) | 2000-05-01 | 2004-05-26 | Schlumberger Holdings | A method for telemetering data between wellbores |
US6632778B1 (en) | 2000-05-02 | 2003-10-14 | Schlumberger Technology Corporation | Self-diverting resin systems for sand consolidation |
US6457518B1 (en) | 2000-05-05 | 2002-10-01 | Halliburton Energy Services, Inc. | Expandable well screen |
US6357527B1 (en) | 2000-05-05 | 2002-03-19 | Halliburton Energy Services, Inc. | Encapsulated breakers and method for use in treating subterranean formations |
US6415509B1 (en) | 2000-05-18 | 2002-07-09 | Halliburton Energy Services, Inc. | Methods of fabricating a thin-wall expandable well screen assembly |
WO2001094744A1 (en) | 2000-06-06 | 2001-12-13 | T R Oil Services Limited | Microcapsule well treatment |
CN1200971C (en) | 2000-06-12 | 2005-05-11 | 三井化学株式会社 | Phenolic resin composition |
US6450260B1 (en) | 2000-07-07 | 2002-09-17 | Schlumberger Technology Corporation | Sand consolidation with flexible gel system |
US6408943B1 (en) | 2000-07-17 | 2002-06-25 | Halliburton Energy Services, Inc. | Method and apparatus for placing and interrogating downhole sensors |
US6202751B1 (en) | 2000-07-28 | 2001-03-20 | Halliburton Energy Sevices, Inc. | Methods and compositions for forming permeable cement sand screens in well bores |
US6422314B1 (en) | 2000-08-01 | 2002-07-23 | Halliburton Energy Services, Inc. | Well drilling and servicing fluids and methods of removing filter cake deposited thereby |
US6494263B2 (en) | 2000-08-01 | 2002-12-17 | Halliburton Energy Services, Inc. | Well drilling and servicing fluids and methods of removing filter cake deposited thereby |
US6552333B1 (en) | 2000-08-16 | 2003-04-22 | Halliburton Energy Services, Inc. | Apparatus and methods for determining gravel pack quality |
US6478092B2 (en) | 2000-09-11 | 2002-11-12 | Baker Hughes Incorporated | Well completion method and apparatus |
MXPA03001910A (en) | 2000-09-12 | 2003-06-19 | Sofitech Nv | Evaluation of multilayer reservoirs. |
US6439310B1 (en) | 2000-09-15 | 2002-08-27 | Scott, Iii George L. | Real-time reservoir fracturing process |
US6372678B1 (en) | 2000-09-28 | 2002-04-16 | Fairmount Minerals, Ltd | Proppant composition for gas and oil well fracturing |
US6476169B1 (en) | 2000-09-28 | 2002-11-05 | Halliburton Energy Services, Inc. | Methods of reducing subterranean formation water permeability |
US6364016B1 (en) | 2000-10-26 | 2002-04-02 | Halliburton Energy Services, Inc. | Methods of reducing the water permeability of subterranean formations |
US6543545B1 (en) | 2000-10-27 | 2003-04-08 | Halliburton Energy Services, Inc. | Expandable sand control device and specialized completion system and method |
US20040011534A1 (en) | 2002-07-16 | 2004-01-22 | Simonds Floyd Randolph | Apparatus and method for completing an interval of a wellbore while drilling |
US6405796B1 (en) | 2000-10-30 | 2002-06-18 | Xerox Corporation | Method for improving oil recovery using an ultrasound technique |
GB0028264D0 (en) | 2000-11-20 | 2001-01-03 | Norske Stats Oljeselskap | Well treatment |
US20020070020A1 (en) | 2000-12-08 | 2002-06-13 | Nguyen Philip D. | Completing wells in unconsolidated formations |
US6439309B1 (en) | 2000-12-13 | 2002-08-27 | Bj Services Company | Compositions and methods for controlling particulate movement in wellbores and subterranean formations |
US6481501B2 (en) * | 2000-12-19 | 2002-11-19 | Intevep, S.A. | Method and apparatus for drilling and completing a well |
US6648501B2 (en) | 2000-12-19 | 2003-11-18 | Wenger Manufacturing, Inc. | System for homogeneously mixing plural incoming product streams of different composition |
US6627719B2 (en) | 2001-01-31 | 2003-09-30 | Ondeo Nalco Company | Cationic latex terpolymers for sludge dewatering |
US6933381B2 (en) | 2001-02-02 | 2005-08-23 | Charles B. Mallon | Method of preparing modified cellulose ether |
US6729405B2 (en) | 2001-02-15 | 2004-05-04 | Bj Services Company | High temperature flexible cementing compositions and methods for using same |
US6321841B1 (en) | 2001-02-21 | 2001-11-27 | Halliburton Energy Services, Inc. | Methods of sealing pipe strings in disposal wells |
US6767868B2 (en) | 2001-02-22 | 2004-07-27 | Bj Services Company | Breaker system for fracturing fluids used in fracturing oil bearing formations |
US6605570B2 (en) | 2001-03-01 | 2003-08-12 | Schlumberger Technology Corporation | Compositions and methods to control fluid loss in surfactant-based wellbore service fluids |
US6557634B2 (en) | 2001-03-06 | 2003-05-06 | Halliburton Energy Services, Inc. | Apparatus and method for gravel packing an interval of a wellbore |
US6359047B1 (en) | 2001-03-20 | 2002-03-19 | Isp Investments Inc. | Gas hydrate inhibitor |
CA2443390C (en) | 2001-04-16 | 2009-12-15 | Halliburton Energy Services, Inc. | Methods of treating subterranean zones penetrated by well bores |
US6510896B2 (en) | 2001-05-04 | 2003-01-28 | Weatherford/Lamb, Inc. | Apparatus and methods for utilizing expandable sand screen in wellbores |
US6659179B2 (en) | 2001-05-18 | 2003-12-09 | Halliburton Energy Serv Inc | Method of controlling proppant flowback in a well |
MXPA03010715A (en) | 2001-05-23 | 2005-03-07 | Core Lab L P | Method of determining the extent of recovery of materials injected into oil wells. |
US7080688B2 (en) | 2003-08-14 | 2006-07-25 | Halliburton Energy Services, Inc. | Compositions and methods for degrading filter cake |
US6488091B1 (en) | 2001-06-11 | 2002-12-03 | Halliburton Energy Services, Inc. | Subterranean formation treating fluid concentrates, treating fluids and methods |
US20020189808A1 (en) | 2001-06-13 | 2002-12-19 | Nguyen Philip D. | Methods and apparatus for gravel packing or frac packing wells |
US7056868B2 (en) | 2001-07-30 | 2006-06-06 | Cabot Corporation | Hydrophobe associative polymers and compositions and methods employing them |
US6642309B2 (en) | 2001-08-14 | 2003-11-04 | Kaneka Corporation | Curable resin composition |
US6830104B2 (en) | 2001-08-14 | 2004-12-14 | Halliburton Energy Services, Inc. | Well shroud and sand control screen apparatus and completion method |
US6632892B2 (en) | 2001-08-21 | 2003-10-14 | General Electric Company | Composition comprising silicone epoxy resin, hydroxyl compound, anhydride and curing catalyst |
JP2003064152A (en) | 2001-08-23 | 2003-03-05 | Japan Epoxy Resin Kk | Modified epoxy resin composition and method for producing the same and solventless type coating using the same composition |
US6938693B2 (en) | 2001-10-31 | 2005-09-06 | Schlumberger Technology Corporation | Methods for controlling screenouts |
US6837309B2 (en) | 2001-09-11 | 2005-01-04 | Schlumberger Technology Corporation | Methods and fluid compositions designed to cause tip screenouts |
US6367549B1 (en) | 2001-09-21 | 2002-04-09 | Halliburton Energy Services, Inc. | Methods and ultra-low density sealing compositions for sealing pipe in well bores |
AU2002327694A1 (en) | 2001-09-26 | 2003-04-07 | Claude E. Cooke Jr. | Method and materials for hydraulic fracturing of wells |
US6662874B2 (en) | 2001-09-28 | 2003-12-16 | Halliburton Energy Services, Inc. | System and method for fracturing a subterranean well formation for improving hydrocarbon production |
US6601648B2 (en) | 2001-10-22 | 2003-08-05 | Charles D. Ebinger | Well completion method |
US6855672B2 (en) | 2001-11-07 | 2005-02-15 | Baker Hughes Incorporated | Copolymers useful for gelling acids |
US6753299B2 (en) | 2001-11-09 | 2004-06-22 | Badger Mining Corporation | Composite silica proppant material |
US6497283B1 (en) | 2001-11-19 | 2002-12-24 | Halliburton Energy Services, Inc. | Well cement additives, compositions and methods |
US6790812B2 (en) | 2001-11-30 | 2004-09-14 | Baker Hughes Incorporated | Acid soluble, high fluid loss pill for lost circulation |
US6626241B2 (en) | 2001-12-06 | 2003-09-30 | Halliburton Energy Services, Inc. | Method of frac packing through existing gravel packed screens |
US6861394B2 (en) | 2001-12-19 | 2005-03-01 | M-I L.L.C. | Internal breaker |
US6569983B1 (en) | 2001-12-20 | 2003-05-27 | Ondeo Nalco Energy Services, L.P. | Method and composition for recovering hydrocarbon fluids from a subterranean reservoir |
US6962200B2 (en) | 2002-01-08 | 2005-11-08 | Halliburton Energy Services, Inc. | Methods and compositions for consolidating proppant in subterranean fractures |
US6668926B2 (en) | 2002-01-08 | 2003-12-30 | Halliburton Energy Services, Inc. | Methods of consolidating proppant in subterranean fractures |
US7343973B2 (en) | 2002-01-08 | 2008-03-18 | Halliburton Energy Services, Inc. | Methods of stabilizing surfaces of subterranean formations |
US6725931B2 (en) | 2002-06-26 | 2004-04-27 | Halliburton Energy Services, Inc. | Methods of consolidating proppant and controlling fines in wells |
US7267171B2 (en) | 2002-01-08 | 2007-09-11 | Halliburton Energy Services, Inc. | Methods and compositions for stabilizing the surface of a subterranean formation |
US7216711B2 (en) | 2002-01-08 | 2007-05-15 | Halliburton Eenrgy Services, Inc. | Methods of coating resin and blending resin-coated proppant |
US6608162B1 (en) | 2002-03-15 | 2003-08-19 | Borden Chemical, Inc. | Spray-dried phenol formaldehyde resins |
US6830105B2 (en) | 2002-03-26 | 2004-12-14 | Halliburton Energy Services, Inc. | Proppant flowback control using elastomeric component |
US6787506B2 (en) | 2002-04-03 | 2004-09-07 | Nalco Energy Services, L.P. | Use of dispersion polymers as friction reducers in aqueous fracturing fluids |
US6852173B2 (en) | 2002-04-05 | 2005-02-08 | Boc, Inc. | Liquid-assisted cryogenic cleaning |
US6691780B2 (en) | 2002-04-18 | 2004-02-17 | Halliburton Energy Services, Inc. | Tracking of particulate flowback in subterranean wells |
US6725930B2 (en) | 2002-04-19 | 2004-04-27 | Schlumberger Technology Corporation | Conductive proppant and method of hydraulic fracturing using the same |
US20030205376A1 (en) | 2002-04-19 | 2003-11-06 | Schlumberger Technology Corporation | Means and Method for Assessing the Geometry of a Subterranean Fracture During or After a Hydraulic Fracturing Treatment |
EP1362978A1 (en) | 2002-05-17 | 2003-11-19 | Resolution Research Nederland B.V. | System for treating an underground formation |
US7153575B2 (en) | 2002-06-03 | 2006-12-26 | Borden Chemical, Inc. | Particulate material having multiple curable coatings and methods for making and using same |
US6838417B2 (en) | 2002-06-05 | 2005-01-04 | Halliburton Energy Services, Inc. | Compositions and methods including formate brines for conformance control |
US6732800B2 (en) | 2002-06-12 | 2004-05-11 | Schlumberger Technology Corporation | Method of completing a well in an unconsolidated formation |
US6702044B2 (en) | 2002-06-13 | 2004-03-09 | Halliburton Energy Services, Inc. | Methods of consolidating formations or forming chemical casing or both while drilling |
US6840318B2 (en) | 2002-06-20 | 2005-01-11 | Schlumberger Technology Corporation | Method for treating subterranean formation |
US7049272B2 (en) | 2002-07-16 | 2006-05-23 | Santrol, Inc. | Downhole chemical delivery system for oil and gas wells |
US6877560B2 (en) | 2002-07-19 | 2005-04-12 | Halliburton Energy Services | Methods of preventing the flow-back of particulates deposited in subterranean formations |
US6776235B1 (en) | 2002-07-23 | 2004-08-17 | Schlumberger Technology Corporation | Hydraulic fracturing method |
US7428037B2 (en) | 2002-07-24 | 2008-09-23 | Carl Zeiss Smt Ag | Optical component that includes a material having a thermal longitudinal expansion with a zero crossing |
US6886635B2 (en) | 2002-08-28 | 2005-05-03 | Tetra Technologies, Inc. | Filter cake removal fluid and method |
US6705400B1 (en) | 2002-08-28 | 2004-03-16 | Halliburton Energy Services, Inc. | Methods and compositions for forming subterranean fractures containing resilient proppant packs |
US6832651B2 (en) | 2002-08-29 | 2004-12-21 | Halliburton Energy Services, Inc. | Cement composition exhibiting improved resilience/toughness and method for using same |
US6887834B2 (en) | 2002-09-05 | 2005-05-03 | Halliburton Energy Services, Inc. | Methods and compositions for consolidating proppant in subterranean fractures |
US6742590B1 (en) | 2002-09-05 | 2004-06-01 | Halliburton Energy Services, Inc. | Methods of treating subterranean formations using solid particles and other larger solid materials |
US7741251B2 (en) | 2002-09-06 | 2010-06-22 | Halliburton Energy Services, Inc. | Compositions and methods of stabilizing subterranean formations containing reactive shales |
US7091159B2 (en) | 2002-09-06 | 2006-08-15 | Halliburton Energy Services, Inc. | Compositions for and methods of stabilizing subterranean formations containing clays |
US6832650B2 (en) | 2002-09-11 | 2004-12-21 | Halliburton Energy Services, Inc. | Methods of reducing or preventing particulate flow-back in wells |
US6817414B2 (en) | 2002-09-20 | 2004-11-16 | M-I Llc | Acid coated sand for gravel pack and filter cake clean-up |
US6935432B2 (en) | 2002-09-20 | 2005-08-30 | Halliburton Energy Services, Inc. | Method and apparatus for forming an annular barrier in a wellbore |
US6832655B2 (en) | 2002-09-27 | 2004-12-21 | Bj Services Company | Method for cleaning gravel packs |
US6776236B1 (en) | 2002-10-16 | 2004-08-17 | Halliburton Energy Services, Inc. | Methods of completing wells in unconsolidated formations |
MXPA05003835A (en) | 2002-10-28 | 2005-06-22 | Schlumberger Technology Bv | Self-destructing filter cake. |
US7008908B2 (en) | 2002-11-22 | 2006-03-07 | Schlumberger Technology Corporation | Selective stimulation with selective water reduction |
US6766858B2 (en) | 2002-12-04 | 2004-07-27 | Halliburton Energy Services, Inc. | Method for managing the production of a well |
US6846420B2 (en) | 2002-12-19 | 2005-01-25 | Halliburton Energy Services, Inc. | Process for removing oil from solid materials recovered from a well bore |
WO2004057152A1 (en) | 2002-12-19 | 2004-07-08 | Schlumberger Canada Limited | Method for providing treatment chemicals in a subterranean well |
GB2399362B (en) | 2003-01-17 | 2005-02-02 | Bj Services Co | Crosslinking delaying agents for acid fluids |
US6892813B2 (en) | 2003-01-30 | 2005-05-17 | Halliburton Energy Services, Inc. | Methods for preventing fracture proppant flowback |
US6851474B2 (en) | 2003-02-06 | 2005-02-08 | Halliburton Energy Services, Inc. | Methods of preventing gravel loss in through-tubing vent-screen well completions |
US6913081B2 (en) | 2003-02-06 | 2005-07-05 | Baker Hughes Incorporated | Combined scale inhibitor and water control treatments |
US6866099B2 (en) | 2003-02-12 | 2005-03-15 | Halliburton Energy Services, Inc. | Methods of completing wells in unconsolidated subterranean zones |
US7220708B2 (en) | 2003-02-27 | 2007-05-22 | Halliburton Energy Services, Inc. | Drilling fluid component |
US20040211561A1 (en) | 2003-03-06 | 2004-10-28 | Nguyen Philip D. | Methods and compositions for consolidating proppant in fractures |
CA2644213C (en) | 2003-03-18 | 2013-10-15 | Bj Services Company | Method of treating subterranean formations using mixed density proppants or sequential proppant stages |
US6764981B1 (en) | 2003-03-21 | 2004-07-20 | Halliburton Energy Services, Inc. | Well treatment fluid and methods with oxidized chitosan-based compound |
US6981552B2 (en) | 2003-03-21 | 2006-01-03 | Halliburton Energy Services, Inc. | Well treatment fluid and methods with oxidized polysaccharide-based polymers |
US7007752B2 (en) | 2003-03-21 | 2006-03-07 | Halliburton Energy Services, Inc. | Well treatment fluid and methods with oxidized polysaccharide-based polymers |
US6962203B2 (en) | 2003-03-24 | 2005-11-08 | Owen Oil Tools Lp | One trip completion process |
US7114570B2 (en) | 2003-04-07 | 2006-10-03 | Halliburton Energy Services, Inc. | Methods and compositions for stabilizing unconsolidated subterranean formations |
US20040211559A1 (en) | 2003-04-25 | 2004-10-28 | Nguyen Philip D. | Methods and apparatus for completing unconsolidated lateral well bores |
US6951250B2 (en) | 2003-05-13 | 2005-10-04 | Halliburton Energy Services, Inc. | Sealant compositions and methods of using the same to isolate a subterranean zone from a disposal well |
US20040231845A1 (en) | 2003-05-15 | 2004-11-25 | Cooke Claude E. | Applications of degradable polymers in wells |
US8181703B2 (en) | 2003-05-16 | 2012-05-22 | Halliburton Energy Services, Inc. | Method useful for controlling fluid loss in subterranean formations |
US8631869B2 (en) | 2003-05-16 | 2014-01-21 | Leopoldo Sierra | Methods useful for controlling fluid loss in subterranean treatments |
US20040229756A1 (en) | 2003-05-16 | 2004-11-18 | Eoff Larry S. | Method for stimulating hydrocarbon production and reducing the production of water from a subterranean formation |
US7182136B2 (en) | 2003-07-02 | 2007-02-27 | Halliburton Energy Services, Inc. | Methods of reducing water permeability for acidizing a subterranean formation |
US8251141B2 (en) | 2003-05-16 | 2012-08-28 | Halliburton Energy Services, Inc. | Methods useful for controlling fluid loss during sand control operations |
US7117942B2 (en) | 2004-06-29 | 2006-10-10 | Halliburton Energy Services, Inc. | Methods useful for controlling fluid loss during sand control operations |
US8278250B2 (en) | 2003-05-16 | 2012-10-02 | Halliburton Energy Services, Inc. | Methods useful for diverting aqueous fluids in subterranean operations |
US7759292B2 (en) | 2003-05-16 | 2010-07-20 | Halliburton Energy Services, Inc. | Methods and compositions for reducing the production of water and stimulating hydrocarbon production from a subterranean formation |
US8091638B2 (en) | 2003-05-16 | 2012-01-10 | Halliburton Energy Services, Inc. | Methods useful for controlling fluid loss in subterranean formations |
US6978836B2 (en) | 2003-05-23 | 2005-12-27 | Halliburton Energy Services, Inc. | Methods for controlling water and particulate production |
US7114560B2 (en) | 2003-06-23 | 2006-10-03 | Halliburton Energy Services, Inc. | Methods for enhancing treatment fluid placement in a subterranean formation |
US7025134B2 (en) | 2003-06-23 | 2006-04-11 | Halliburton Energy Services, Inc. | Surface pulse system for injection wells |
US7013976B2 (en) | 2003-06-25 | 2006-03-21 | Halliburton Energy Services, Inc. | Compositions and methods for consolidating unconsolidated subterranean formations |
US7178596B2 (en) | 2003-06-27 | 2007-02-20 | Halliburton Energy Services, Inc. | Methods for improving proppant pack permeability and fracture conductivity in a subterranean well |
US7032663B2 (en) | 2003-06-27 | 2006-04-25 | Halliburton Energy Services, Inc. | Permeable cement and sand control methods utilizing permeable cement in subterranean well bores |
US7044224B2 (en) | 2003-06-27 | 2006-05-16 | Halliburton Energy Services, Inc. | Permeable cement and methods of fracturing utilizing permeable cement in subterranean well bores |
US7228904B2 (en) | 2003-06-27 | 2007-06-12 | Halliburton Energy Services, Inc. | Compositions and methods for improving fracture conductivity in a subterranean well |
US7044220B2 (en) | 2003-06-27 | 2006-05-16 | Halliburton Energy Services, Inc. | Compositions and methods for improving proppant pack permeability and fracture conductivity in a subterranean well |
US7036587B2 (en) | 2003-06-27 | 2006-05-02 | Halliburton Energy Services, Inc. | Methods of diverting treating fluids in subterranean zones and degradable diverting materials |
US6981560B2 (en) | 2003-07-03 | 2006-01-03 | Halliburton Energy Services, Inc. | Method and apparatus for treating a productive zone while drilling |
US7021379B2 (en) | 2003-07-07 | 2006-04-04 | Halliburton Energy Services, Inc. | Methods and compositions for enhancing consolidation strength of proppant in subterranean fractures |
US7066258B2 (en) | 2003-07-08 | 2006-06-27 | Halliburton Energy Services, Inc. | Reduced-density proppants and methods of using reduced-density proppants to enhance their transport in well bores and fractures |
US7104325B2 (en) | 2003-07-09 | 2006-09-12 | Halliburton Energy Services, Inc. | Methods of consolidating subterranean zones and compositions therefor |
US20050028976A1 (en) | 2003-08-05 | 2005-02-10 | Nguyen Philip D. | Compositions and methods for controlling the release of chemicals placed on particulates |
US7036589B2 (en) | 2003-08-14 | 2006-05-02 | Halliburton Energy Services, Inc. | Methods for fracturing stimulation |
US7059406B2 (en) | 2003-08-26 | 2006-06-13 | Halliburton Energy Services, Inc. | Production-enhancing completion methods |
US7156194B2 (en) | 2003-08-26 | 2007-01-02 | Halliburton Energy Services, Inc. | Methods of drilling and consolidating subterranean formation particulate |
US7237609B2 (en) | 2003-08-26 | 2007-07-03 | Halliburton Energy Services, Inc. | Methods for producing fluids from acidized and consolidated portions of subterranean formations |
US7017665B2 (en) | 2003-08-26 | 2006-03-28 | Halliburton Energy Services, Inc. | Strengthening near well bore subterranean formations |
US7131491B2 (en) | 2004-06-09 | 2006-11-07 | Halliburton Energy Services, Inc. | Aqueous-based tackifier fluids and methods of use |
US7040403B2 (en) | 2003-08-27 | 2006-05-09 | Halliburton Energy Services, Inc. | Methods for controlling migration of particulates in a subterranean formation |
US7204311B2 (en) | 2003-08-27 | 2007-04-17 | Halliburton Energy Services, Inc. | Methods for controlling migration of particulates in a subterranean formation |
US8076271B2 (en) | 2004-06-09 | 2011-12-13 | Halliburton Energy Services, Inc. | Aqueous tackifier and methods of controlling particulates |
US6997259B2 (en) | 2003-09-05 | 2006-02-14 | Halliburton Energy Services, Inc. | Methods for forming a permeable and stable mass in a subterranean formation |
US7032667B2 (en) | 2003-09-10 | 2006-04-25 | Halliburtonn Energy Services, Inc. | Methods for enhancing the consolidation strength of resin coated particulates |
US7081439B2 (en) | 2003-11-13 | 2006-07-25 | Schlumberger Technology Corporation | Methods for controlling the fluid loss properties of viscoelastic surfactant based fluids |
US7063150B2 (en) | 2003-11-25 | 2006-06-20 | Halliburton Energy Services, Inc. | Methods for preparing slurries of coated particulates |
US20050139359A1 (en) | 2003-12-29 | 2005-06-30 | Noble Drilling Services Inc. | Multiple expansion sand screen system and method |
US20050145385A1 (en) | 2004-01-05 | 2005-07-07 | Nguyen Philip D. | Methods of well stimulation and completion |
US7563750B2 (en) | 2004-01-24 | 2009-07-21 | Halliburton Energy Services, Inc. | Methods and compositions for the diversion of aqueous injection fluids in injection operations |
US20050173116A1 (en) | 2004-02-10 | 2005-08-11 | Nguyen Philip D. | Resin compositions and methods of using resin compositions to control proppant flow-back |
US7159656B2 (en) | 2004-02-18 | 2007-01-09 | Halliburton Energy Services, Inc. | Methods of reducing the permeabilities of horizontal well bore sections |
US7211547B2 (en) | 2004-03-03 | 2007-05-01 | Halliburton Energy Services, Inc. | Resin compositions and methods of using such resin compositions in subterranean applications |
US7063151B2 (en) | 2004-03-05 | 2006-06-20 | Halliburton Energy Services, Inc. | Methods of preparing and using coated particulates |
US20050194142A1 (en) * | 2004-03-05 | 2005-09-08 | Nguyen Philip D. | Compositions and methods for controlling unconsolidated particulates |
US7503404B2 (en) | 2004-04-14 | 2009-03-17 | Halliburton Energy Services, Inc, | Methods of well stimulation during drilling operations |
US7114568B2 (en) | 2004-04-15 | 2006-10-03 | Halliburton Energy Services, Inc. | Hydrophobically modified polymers for a well completion spacer fluid |
US7207387B2 (en) | 2004-04-15 | 2007-04-24 | Halliburton Energy Services, Inc. | Methods and compositions for use with spacer fluids used in subterranean well bores |
US7128148B2 (en) | 2004-04-16 | 2006-10-31 | Halliburton Energy Services, Inc. | Well treatment fluid and methods for blocking permeability of a subterranean zone |
US20050263283A1 (en) * | 2004-05-25 | 2005-12-01 | Nguyen Philip D | Methods for stabilizing and stimulating wells in unconsolidated subterranean formations |
US7541318B2 (en) | 2004-05-26 | 2009-06-02 | Halliburton Energy Services, Inc. | On-the-fly preparation of proppant and its use in subterranean operations |
US20050269101A1 (en) | 2004-06-04 | 2005-12-08 | Halliburton Energy Services | Methods of treating subterranean formations using low-molecular-weight fluids |
US20050269099A1 (en) * | 2004-06-04 | 2005-12-08 | Halliburton Energy Services | Methods of treating subterranean formations using low-molecular-weight fluids |
US20050284637A1 (en) | 2004-06-04 | 2005-12-29 | Halliburton Energy Services | Methods of treating subterranean formations using low-molecular-weight fluids |
US7299875B2 (en) | 2004-06-08 | 2007-11-27 | Halliburton Energy Services, Inc. | Methods for controlling particulate migration |
US7073581B2 (en) | 2004-06-15 | 2006-07-11 | Halliburton Energy Services, Inc. | Electroconductive proppant compositions and related methods |
US7216707B2 (en) | 2004-06-21 | 2007-05-15 | Halliburton Energy Services, Inc. | Cement compositions with improved fluid loss characteristics and methods of cementing using such cement compositions |
WO2006022456A1 (en) | 2004-08-27 | 2006-03-02 | Canon Kabushiki Kaisha | Water-base ink, ink jet recording method, ink cartridge, recording unit, ink jet recording apparatus, and image forming method |
US7255169B2 (en) | 2004-09-09 | 2007-08-14 | Halliburton Energy Services, Inc. | Methods of creating high porosity propped fractures |
US20060052251A1 (en) | 2004-09-09 | 2006-03-09 | Anderson David K | Time release multisource marker and method of deployment |
US7281580B2 (en) * | 2004-09-09 | 2007-10-16 | Halliburton Energy Services, Inc. | High porosity fractures and methods of creating high porosity fractures |
US7093658B2 (en) | 2004-10-29 | 2006-08-22 | Halliburton Energy Services, Inc. | Foamed treatment fluids, foaming additives, and associated methods |
US7237612B2 (en) | 2004-11-17 | 2007-07-03 | Halliburton Energy Services, Inc. | Methods of initiating a fracture tip screenout |
US7461696B2 (en) | 2004-11-30 | 2008-12-09 | Halliburton Energy Services, Inc. | Methods of fracturing using fly ash aggregates |
US7325608B2 (en) | 2004-12-01 | 2008-02-05 | Halliburton Energy Services, Inc. | Methods of hydraulic fracturing and of propping fractures in subterranean formations |
US7281581B2 (en) | 2004-12-01 | 2007-10-16 | Halliburton Energy Services, Inc. | Methods of hydraulic fracturing and of propping fractures in subterranean formations |
US7273099B2 (en) | 2004-12-03 | 2007-09-25 | Halliburton Energy Services, Inc. | Methods of stimulating a subterranean formation comprising multiple production intervals |
US7398825B2 (en) | 2004-12-03 | 2008-07-15 | Halliburton Energy Services, Inc. | Methods of controlling sand and water production in subterranean zones |
US7883740B2 (en) | 2004-12-12 | 2011-02-08 | Halliburton Energy Services, Inc. | Low-quality particulates and methods of making and using improved low-quality particulates |
US7334635B2 (en) | 2005-01-14 | 2008-02-26 | Halliburton Energy Services, Inc. | Methods for fracturing subterranean wells |
US8703659B2 (en) | 2005-01-24 | 2014-04-22 | Halliburton Energy Services, Inc. | Sealant composition comprising a gel system and a reduced amount of cement for a permeable zone downhole |
US7334636B2 (en) | 2005-02-08 | 2008-02-26 | Halliburton Energy Services, Inc. | Methods of creating high-porosity propped fractures using reticulated foam |
US7448451B2 (en) | 2005-03-29 | 2008-11-11 | Halliburton Energy Services, Inc. | Methods for controlling migration of particulates in a subterranean formation |
US7673686B2 (en) | 2005-03-29 | 2010-03-09 | Halliburton Energy Services, Inc. | Method of stabilizing unconsolidated formation for sand control |
US20060240995A1 (en) | 2005-04-23 | 2006-10-26 | Halliburton Energy Services, Inc. | Methods of using resins in subterranean formations |
BRPI0610614A2 (en) | 2005-05-02 | 2010-07-13 | Trican Well Services Ltd | method for transporting aqueous sludge by particulate hydrophobization |
US7500519B2 (en) | 2005-05-20 | 2009-03-10 | Halliburton Energy Services, Inc. | Methods of modifying fracture faces and other surfaces in subterranean formations |
US20060264332A1 (en) | 2005-05-20 | 2006-11-23 | Halliburton Energy Services, Inc. | Methods of using reactive surfactants in subterranean operations |
US8158720B2 (en) | 2005-06-28 | 2012-04-17 | Halliburton Energy Services, Inc. | Crosslinkable polymer compositions and associated methods |
US7318474B2 (en) | 2005-07-11 | 2008-01-15 | Halliburton Energy Services, Inc. | Methods and compositions for controlling formation fines and reducing proppant flow-back |
US7493957B2 (en) | 2005-07-15 | 2009-02-24 | Halliburton Energy Services, Inc. | Methods for controlling water and sand production in subterranean wells |
US20080110624A1 (en) | 2005-07-15 | 2008-05-15 | Halliburton Energy Services, Inc. | Methods for controlling water and particulate production in subterranean wells |
US20070114032A1 (en) | 2005-11-22 | 2007-05-24 | Stegent Neil A | Methods of consolidating unconsolidated particulates in subterranean formations |
US7392847B2 (en) | 2005-12-09 | 2008-07-01 | Clearwater International, Llc | Aggregating reagents, modified particulate metal-oxides, and methods for making and using same |
US7350579B2 (en) | 2005-12-09 | 2008-04-01 | Clearwater International Llc | Sand aggregating reagents, modified sands, and methods for making and using same |
US7500521B2 (en) | 2006-07-06 | 2009-03-10 | Halliburton Energy Services, Inc. | Methods of enhancing uniform placement of a resin in a subterranean formation |
US7678743B2 (en) | 2006-09-20 | 2010-03-16 | Halliburton Energy Services, Inc. | Drill-in fluids and associated methods |
US7687438B2 (en) | 2006-09-20 | 2010-03-30 | Halliburton Energy Services, Inc. | Drill-in fluids and associated methods |
US7678742B2 (en) | 2006-09-20 | 2010-03-16 | Halliburton Energy Services, Inc. | Drill-in fluids and associated methods |
US20080139411A1 (en) | 2006-12-07 | 2008-06-12 | Harris Phillip C | Methods of treating subterranean formations using hydrophobically modified polymers and compositions of the same |
US7730950B2 (en) | 2007-01-19 | 2010-06-08 | Halliburton Energy Services, Inc. | Methods for treating intervals of a subterranean formation having variable permeability |
US7934557B2 (en) | 2007-02-15 | 2011-05-03 | Halliburton Energy Services, Inc. | Methods of completing wells for controlling water and particulate production |
-
2007
- 2007-02-15 US US11/706,737 patent/US7934557B2/en not_active Expired - Fee Related
-
2008
- 2008-02-08 WO PCT/GB2008/000476 patent/WO2008099154A1/en active Application Filing
Patent Citations (11)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US3865600A (en) * | 1972-03-08 | 1975-02-11 | Fosroc Ag | Soil consolidation |
US4091868A (en) * | 1977-03-07 | 1978-05-30 | Diversified Chemical Corporation | Method of treating oil wells |
US4718491A (en) * | 1985-08-29 | 1988-01-12 | Institut Francais Du Petrole | Process for preventing water inflow in an oil- and/or gas-producing well |
US5150754A (en) * | 1991-05-28 | 1992-09-29 | Mobil Oil Corporation | Aqueous and petroleum gel method for preventing water-influx |
US5379841A (en) * | 1992-04-10 | 1995-01-10 | Hoechst Aktiengesellschaft | Method for reducing or completely stopping the influx of water in boreholes for the extraction of oil and/or hydrocarbon gas |
US6920928B1 (en) * | 1998-03-27 | 2005-07-26 | Schlumberger Technology Corporation | Method for water control |
US6228812B1 (en) * | 1998-12-10 | 2001-05-08 | Bj Services Company | Compositions and methods for selective modification of subterranean formation permeability |
US6187839B1 (en) * | 1999-03-03 | 2001-02-13 | Halliburton Energy Services, Inc. | Methods of sealing compositions and methods |
US6283210B1 (en) * | 1999-09-01 | 2001-09-04 | Halliburton Energy Services, Inc. | Proactive conformance for oil or gas wells |
US20040144542A1 (en) * | 2001-05-25 | 2004-07-29 | Luisa Chiappa | Process for reducing the production of water in oil wells |
US20030092578A1 (en) * | 2001-11-15 | 2003-05-15 | Hirasaki George J. | Subterranean formation water permeability reducing methods |
Cited By (13)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US7934557B2 (en) | 2007-02-15 | 2011-05-03 | Halliburton Energy Services, Inc. | Methods of completing wells for controlling water and particulate production |
WO2009087349A1 (en) * | 2008-01-08 | 2009-07-16 | Halliburton Energy Services, Inc. | Methods for controlling water and particulate production in subterranean wells |
CN102250595A (en) * | 2011-05-19 | 2011-11-23 | 中国石油天然气集团公司 | Drilling fluid used for active mud shale drilling |
WO2015016934A1 (en) * | 2013-08-01 | 2015-02-05 | Halliburton Energy Services, Inc. | Resin composition for treatment of a subterranean formation |
US10005951B2 (en) | 2013-08-01 | 2018-06-26 | Halliburton Energy Services, Inc. | Resin composition for treatment of a subterranean formation |
CN104449618A (en) * | 2015-01-06 | 2015-03-25 | 西南石油大学 | Temperature-resisting salt-tolerant high-temperature self-cross-linking onsite polymerization water plugging gel |
EP3420047B1 (en) * | 2016-02-23 | 2023-01-11 | Ecolab USA Inc. | Hydrazide crosslinked polymer emulsions for use in crude oil recovery |
CN111139039B (en) * | 2018-11-02 | 2022-06-10 | 中国石油化工股份有限公司 | Sulfonated phenolic resin graft modified polymer filtrate reducer and preparation method thereof |
CN111139042A (en) * | 2018-11-02 | 2020-05-12 | 中国石油化工股份有限公司 | Resin modified polymer fluid loss agent based on degradation and preparation method thereof |
CN111139039A (en) * | 2018-11-02 | 2020-05-12 | 中国石油化工股份有限公司 | Sulfonated phenolic resin graft modified polymer filtrate reducer and preparation method thereof |
CN111139042B (en) * | 2018-11-02 | 2022-06-10 | 中国石油化工股份有限公司 | Resin modified polymer fluid loss agent based on degradation and preparation method thereof |
WO2020146885A1 (en) * | 2019-01-11 | 2020-07-16 | Saudi Arabian Oil Company | Methods and compositions for controlling excess water production |
CN110387222A (en) * | 2019-08-01 | 2019-10-29 | 西南石油大学 | A kind of porous gel sealing agent, preparation method and application |
Also Published As
Publication number | Publication date |
---|---|
US20080196897A1 (en) | 2008-08-21 |
US7934557B2 (en) | 2011-05-03 |
Similar Documents
Publication | Publication Date | Title |
---|---|---|
US7934557B2 (en) | Methods of completing wells for controlling water and particulate production | |
US7398825B2 (en) | Methods of controlling sand and water production in subterranean zones | |
US7730950B2 (en) | Methods for treating intervals of a subterranean formation having variable permeability | |
US7493957B2 (en) | Methods for controlling water and sand production in subterranean wells | |
US7441598B2 (en) | Methods of stabilizing unconsolidated subterranean formations | |
CA2630319C (en) | Methods of consolidating unconsolidated particulates in subterranean formations | |
US7665517B2 (en) | Methods of cleaning sand control screens and gravel packs | |
US20100186954A1 (en) | Methods for controlling water and particulate production in subterranean wells | |
US7413010B2 (en) | Remediation of subterranean formations using vibrational waves and consolidating agents | |
US7766099B2 (en) | Methods of drilling and consolidating subterranean formation particulates | |
US7690431B2 (en) | Methods for controlling migration of particulates in a subterranean formation | |
WO2007054708A1 (en) | Methods for treating a subterranean formation with a curable composition using a jetting tool | |
WO2009122120A1 (en) | Methods for placement of sealant in subterranean intervals | |
US20050263283A1 (en) | Methods for stabilizing and stimulating wells in unconsolidated subterranean formations |
Legal Events
Date | Code | Title | Description |
---|---|---|---|
121 | Ep: the epo has been informed by wipo that ep was designated in this application |
Ref document number: 08709372 Country of ref document: EP Kind code of ref document: A1 |
|
NENP | Non-entry into the national phase |
Ref country code: DE |
|
122 | Ep: pct application non-entry in european phase |
Ref document number: 08709372 Country of ref document: EP Kind code of ref document: A1 |