WO2015130815A1 - Settable compositions and methods of use - Google Patents
Settable compositions and methods of use Download PDFInfo
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- WO2015130815A1 WO2015130815A1 PCT/US2015/017564 US2015017564W WO2015130815A1 WO 2015130815 A1 WO2015130815 A1 WO 2015130815A1 US 2015017564 W US2015017564 W US 2015017564W WO 2015130815 A1 WO2015130815 A1 WO 2015130815A1
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- WIPO (PCT)
- Prior art keywords
- wellbore
- composition
- settable
- settable composition
- settabie
- Prior art date
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Classifications
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- C—CHEMISTRY; METALLURGY
- C04—CEMENTS; CONCRETE; ARTIFICIAL STONE; CERAMICS; REFRACTORIES
- C04B—LIME, MAGNESIA; SLAG; CEMENTS; COMPOSITIONS THEREOF, e.g. MORTARS, CONCRETE OR LIKE BUILDING MATERIALS; ARTIFICIAL STONE; CERAMICS; REFRACTORIES; TREATMENT OF NATURAL STONE
- C04B14/00—Use of inorganic materials as fillers, e.g. pigments, for mortars, concrete or artificial stone; Treatment of inorganic materials specially adapted to enhance their filling properties in mortars, concrete or artificial stone
- C04B14/02—Granular materials, e.g. microballoons
- C04B14/04—Silica-rich materials; Silicates
- C04B14/14—Minerals of vulcanic origin
- C04B14/16—Minerals of vulcanic origin porous, e.g. pumice
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- C—CHEMISTRY; METALLURGY
- C04—CEMENTS; CONCRETE; ARTIFICIAL STONE; CERAMICS; REFRACTORIES
- C04B—LIME, MAGNESIA; SLAG; CEMENTS; COMPOSITIONS THEREOF, e.g. MORTARS, CONCRETE OR LIKE BUILDING MATERIALS; ARTIFICIAL STONE; CERAMICS; REFRACTORIES; TREATMENT OF NATURAL STONE
- C04B28/00—Compositions of mortars, concrete or artificial stone, containing inorganic binders or the reaction product of an inorganic and an organic binder, e.g. polycarboxylate cements
- C04B28/18—Compositions of mortars, concrete or artificial stone, containing inorganic binders or the reaction product of an inorganic and an organic binder, e.g. polycarboxylate cements containing mixtures of the silica-lime type
-
- 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
- C09K8/40—Spacer compositions, e.g. compositions used to separate well-drilling from cementing masses
-
- 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
- C09K8/42—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells
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- 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
- C09K8/42—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells
- C09K8/46—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells containing inorganic binders, e.g. Portland cement
- C09K8/467—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells containing inorganic binders, e.g. Portland cement containing additives for specific purposes
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- 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
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/10—Sealing or packing boreholes or wells in the borehole
- E21B33/13—Methods or devices for cementing, for plugging holes, crevices, or the like
Definitions
- Embodiments relate to subterranean operations and, in certain embodiments, to settable compositions and methods of using settable compositions in subterranean formations.
- a dril ling fluid may be used to, among other things, cool the drill bit, lubricate the rotating drill string to prevent it from sticking to the walls of the well bore, prevent blowouts by serving as a hydrostatic head to counteract the sudden entrance into the well bore of high pressure formation fluids, and remove drill cuttings from the well bore.
- a drilling fluid may be circulated downwardly through a drill pipe and drill bit and then upwardly through the wellbore to the surface.
- the drilling fluid used may be any number of fluids (gaseous or liquid) and mixtures of fluids and solids (such as solid suspensions, mixtures, and emulsions).
- the drill bit may be withdrawn from the wellbore, and circulation of the drilling fluid is stopped.
- the drilling fluid may be left in the wellbore along with a filter cake of solids from the drilling fluid.
- a pipe string e.g., casing, liners, etc.
- the drilling fluid may remain relatively static in the well bore for a relatively long time period, for example, up to about 2 weeks or longer.
- drilling fluids While drilling fluids are generally not settable (e.g., they generally do not to form a hardened mass over time), drilling fluids may increase in gel strength over time. Accordingly, during the time period that the drilling fluid is static in the well bore, portions of the drilling fluid may increase in gel strength so that displacement of the drilling fluid from within the well bore may be become more difficult.
- the pipe string may be cemented in place by pumping a cement composition through the pipe string and into the annulus between the pipe string and the walls of the well bore whereby the drilling fluid in the annulus is displaced therefrom by the cement composition.
- a settable composition (commonly referred to as a "settable spotting composition”) may be used to remove dril ling fluid and prevent the drilling fluid filter cake from interfering with subsequent primary cementing operations.
- These settable spotting compositions may be used to at least partial ly displacing the dri ll ing fluid before the dril ling fluid in the wellbore has had a chance to gain significant gel strength, for example, prior to introducing the pipe string into the well bore.
- these settable spotting compositions should not have an undesirable increase in gel strength after being static in the wel lbore for a period of time, for example, up to at least two weeks, so that the settable spotting compositions may be displaced from the wellbore.
- the pipe string to be cemented may be introduced into the wellbore.
- the drilling fluid (if any) and settable spotting composition in the pipe string and annulus should be displaced ahead of the cement composition.
- the settable spotting composition, if any, remaining in fractures or other permeable portions of the subterranean formation should set into a hardened mass, thereby preventing or reducing the entry or flow of formation fluids in the annulus.
- a settable composition may be placed into the wellbore before the casing and consequently the settable composition must remain in a fluid puddle state long enough for the casing string to be placed into the wellbore. Once the casing string is successfully positioned the settable composition may then set into a hardened mass, which may be sealable and/or may prevent the migration of fluids in the wellbore.
- settable compositions have been developed heretofore, challenges exist with their successful use in subterranean cementing operations.
- settable compositions used as settable spotting compositions should ideally remain fluid long enough so that they can ultimately be displaced with the cement composition or any associated spacer fluids.
- settable compositions used in puddle jobs should ideally remain fluid long enough to place and position the casing within the wellbore.
- FIG. 1 il lustrates surface equipment that may be used in the placement of a settable composition in a wellbore in accordance with certain embodiments.
- FIG. 2A illustrates a method for placement of a settable composition into a wellbore annulus in accordance with certain embodiments.
- FIG. 2B illustrates a method for the placement of a settable composition into a wellbore annulus in accordance with certain embodiments.
- FIG. 2C illustrates a method for the placement of a settable composition into a wellbore annulus in accordance with certain embodiments.
- FIG. 2D illustrates a method for the placement of a settable composition into a wellbore annulus in accordance with certain embodiments.
- FIG. 3 illustrates a method for the placement of a settable composition into a wellbore in accordance with certain embodiments.
- FIG. 4 illustrates the placement of a pipe string into a wellbore annulus at least partially filled with a settable composition in accordance with certain embodiments.
- FIG. 5A illustrates a "right-angle" set profile of a settable composition in accordance with certain embodiments.
- FIG. 5B illustrates a gelation set profile of a settable composition in accordance with certain embodiments.
- Embodiments relate to subterranean operations and. in certain embodiments, to settable compositions and methods of using settable compositions in subterranean formations.
- Embodiments of the settable compositions may general ly comprise water, pumice. hydrated lime, and a set retarder.
- the settable compositions may further comprise a set activator.
- embodiments of the settable compositions may be capable of remaining in a pumpable fluid state for an extended period of time— even after activation.
- the settable compositions may remain in a pumpable fluid state for about 1 day. about 3 days, about 5 days, about 7 days, or longer.
- embodiments of the settable composition may maintain low gel strengths for extended periods of time, allowing their displacement after remaining static in the wellbore for a period of time.
- the settable compositions may have a yield point less than 20 lbs./100 ft.
- the settable composition may have an initial set to 50 psi of about 1 day, about 2 days, about 5 days, or longer.
- the settable compositions may ultimately develop reasonable compressive strengths after activation at relatively low temperatures. While the settable compositions may be suitable for a number of subterranean operations, they may be particularly suitable operations where it is desired to have an extended set after placement in the subterranean formation, such as settable spotting compositions and puddle jobs. In embodiments, the settable compositions may be used in subterranean formations having pressures up to about 1 5,000 psi or higher.
- the water used in embodiments of the settable compositions may be from any source provided that it does not contain an excess of compounds that may undesirably affect other components in the settable compositions.
- a settable composition may comprise fresh water or salt water.
- Salt water generally may include one or more dissolved salts therein and may be saturated or unsaturated as desired for a particular application. Seawater or brines may be suitable for use in embodiments.
- the water may be present in an amount sufficient to form a pumpable fluid. In certain embodiments, the water may be present in the settable compositions in an amount in the range of from about 33% to about 200% by weight of the pumice.
- the water may be present in the settable compositions in an amount in the range of from about 35% to about 70% by weight of the pumice.
- the water may be present in the settable compositions in an amount in the range of from about 35% to about 70% by weight of the pumice.
- Embodiments of the settable compositions may comprise pumice.
- pumice is a volcanic rock that can exhibit cementitious properties in that it may set and harden in the presence of hydrated lime and water.
- the pumice may also be ground.
- the pumice may have any particle size distribution as desired for a particular application.
- the pumice may have a d50 particle size distribution in a range of from about 1 micron to about 200 microns. The d50 values may be measured by particle size analyzers such as those manufactured by Malvern Instruments, Worcestershire, United Kingdom.
- the pumice may have a d50 particle size distribution in a range of from about 1 micron to about 200 microns, from about 5 microns to about 1 00 microns, or from about 10 microns to about 25 microns. In one particular embodiment, the pumice may have a d50 particle size distribution of about 1 5 microns or less.
- An example of a suitable pumice is available from Hess Pumice Products, Inc., Malad, Idaho, as DS-325 lightweight aggregate, having a d50 particle size distribution of about 1 5 microns or less. It should be appreciated that particle sizes too small may have mixability problems while particle sizes too large may not be effectively suspended in the compositions.
- Embodiments of the settable compositions may comprise hydrated lime.
- the term "hydrated lime” will be understood to mean calcium hydroxide.
- the hydrated lime may be provided as quicklime (calcium oxide) which hydrates when mixed with water to form the hydrated lime.
- the hydrated lime may be included in embodiments of the settable compositions, for example, to form a hydraulic composition with the pumice.
- the hydrated lime may be included in a pumice-to-hydrated-lime weight ratio of about 10: 1 to about 1 : 1 or about 3 : 1 to about 5 : 1.
- the hydrated lime may be included in the settable compositions in an amount in the range of from about 10% to about 100% by weight of the pumice, for example. In some embodiments, the hydrated lime may be present in an amount ranging between any of and/or including any of about 10%, about 20%, about 40%, about 60%, about 80%, or about 100% by weight of the pumice.
- the settable components present in the settable compositions may consist essentially of the pumice and the hydrated lime.
- the settable components may primarily comprise the pumice and the hydrated lime without any additional components (e.g., Portland cement, fl ash. slag cement) that hydraulical ly set in the presence of water.
- wi l l recognize the appropriate amount of the hydrated lime to incl ude for a chosen appl ication.
- Embodiments of the settable compositions may comprise a set retarder.
- a broad variety of set retarders may be suitable for use in the settable compositions.
- the set retarder may comprise phosphonic acids, such as amino tris(methylene phosphonic acid), ethylenediamine tetra(methylene phosphonic acid), diethylenetriamine penta(methylene phosphonic acid), etc.; l ignosulfonates. such as sodium lignosulfonate, calcium lignosulfonate.
- salts such as stannous sulfate, lead acetate, monobasic calcium phosphate, organic acids, such as citric acid, tartaric acid, etc.
- cellulose derivatives such as hydroxyl ethyl cellulose (H EC) and carboxymethyl hydroxyethyl cel lulose (CM HEC); synthetic co- or ter-polymers comprising sulfonate and carboxylic acid groups such as sulfonate-functionalized acrylamide-acrylic acid copolymers; borate compounds such as alkali borates, sodium metaborate, sodium tetraborate, potassium pentaborate; derivatives thereof, or mixtures thereof.
- suitable set retarders include, among others, phosphonic acid derivatives.
- the set retarder may be present in the settable compositions in an amount sufficient to delay the setting for a desired time.
- the set retarder may be present in the settable compositions in an amount in the range of from about 0.01 % to about 1 0% by weight of the pumice.
- the set retarder may be present in an amount ranging between any of and/or including any of about 0.01 %, about 0.1 %, about 1 %, about 2%, about 4%, about 6%, about 8%, or about 10% by weight of the pumice.
- any embodiment of the settable compositions may comprise one or more set retarders.
- One of ordinary skill in the art, with the benefit of this disclosure, will recognize the appropriate amount of set retarder to include for a chosen application.
- embodiments of the settable compositions may optionally comprise a dispersant.
- suitable dispersants include, without limitation, sulfonated-formaldehyde-based dispersants (e.g., sulfonated acetone formaldehyde condensate), examples of which may include Daxad ® 19 dispersant available from Geo Specialty Chemicals, Ambler, Pennsylvania.
- Other suitable dispersants may be polycarboxylated ether dispersants such as Liquiment ® 5581F and Liquiment ® 514L dispersants available from BASF Corporation Houston. Texas: or Ethacry f"' G dispersant avai lable from Coatex. Genay. France.
- An additional example of a suitable commercial ly available dispersant is CFR '-3 dispersant. available from Hall iburton Energy Services, Inc. Houston. Texas.
- the Liquiment " 5 14L dispersant may comprise 36% by weight of the polycarboxylated ether in water.
- Whi le a variety of dispersants may be used in accordance with embodiments, polycarboxylated ether dispersants may be particularly suitable for use in some embodiments. Without being l imited by theory, it is believed that polycarboxylated ether dispersants may synergistically interact with other components of the settable compositions.
- the polycarboxylated ether dispersants may react with certain set retarders (e.g., phosphonic acid derivatives) resulting in formation of a gel that suspends the pumice and hydrated lime in the settable compositions for an extended period of time.
- set retarders e.g., phosphonic acid derivatives
- the dispersant may be included in the settable compositions in an amount in the range of from about 0.01 % to about 5% by weight of the pumice. In specific embodiments, the dispersant may be present in an amount ranging between any of and/or including any of about 0.01 %, about 0.1 %, about 0.5%, about 1 %, about 2%, about 3%, about 4%, or about 5% by weight of the pumice.
- the dispersant may be included in the settable compositions in an amount in the range of from about 0.01 % to about 5% by weight of the pumice.
- the dispersant may be present in an amount ranging between any of and/or including any of about 0.01 %, about 0.1 %, about 0.5%, about 1 %, about 2%, about 3%, about 4%, or about 5% by weight of the pumice.
- One of ordinary skill in the art, with the benefit of this disclosure, will recognize the appropriate amount of the dispersant to include for a chosen application.
- a viscosifier may be included in the settable compositions.
- the viscosifier may be included to optimize fluid rheology and to stabilize the suspension.
- examples of viscosifiers include swellable clays such as bentonite or biopolymers such as cellulose derivatives (e.g., hydroxyethyl cellulose, carboxymethyl cellulose, carboxymethyl hydroxyethyl cellulose).
- An example of a commercially available viscosifier is SA-101 5TM available from Halliburton Energy Services, Inc., Houston, TX.
- the viscosifier may be included in the settable compositions in an amount in the range of from about 0.01 % to about 0.5% by weight of the pumice.
- the viscosifier may be present in an amount ranging between any of and/or including any of about 0.01 %, about 0.05%, about 0.1 %, about 0.2%, about 0.3%, about 0.4%, or about 0.5% by weight of the pumice.
- the appropriate amount of viscosifier to include for a chosen application.
- Embodiments may include the addition of a set activator to the settable compositions.
- set activator or “activator”, as used herein, refers to an additive that activates a set-delayed or retarded settable composition.
- a set activator may also accelerate the setting of the set-delayed or retarded settable composition.
- the settable compositions may be activated thermally . I n embodiments where the settable compositions are activated thermal ly, the settable compositions are activated by the heat of the subterranean formation in which they are introduced.
- the set activator may be added to the settable compositions prior to pumping the settable compositions into the subterranean formation. Whether to activate the settable composition with a set activator or thermal ly with the heat of the subterranean formation depends on a number of factors, including the downhole temperature and the desire to control slurry rheological and/or strength development properties. At low temperatures, thermal activation is not sufficient to drive hydration in the compositions, and chemical activation is required. However, even at high temperatures, when there is a desire to enhance development of early strength or late strength in the composition, which may, in some embodiments be a function of the slurry's rheology. or when there is a need to suppress, for example, gas/fluid migration, a set activator may allow for control over these properties whereas thermal activation may just initiate hydration and drive the reaction to completion.
- Suitable set activators include, but are not limited to: zeolites, amines such as triethanolamine, diethanolamine; silicates such as sodium silicate; zinc formate; calcium acetate; Groups 1A and II A hydroxides such as sodium hydroxide, magnesium hydroxide, and calcium hydroxide; monovalent salts such as sodium chloride; divalent salts such as calcium chloride; nanosilica (i.e., silica having a particle size of less than or equal to about 100 nanometers); polyphosphates; and combinations thereof. In some embodiments, a combination of the polyphosphate and a monovalent salt may be used for activation.
- the monovalent salt may be any salt that dissociates to form a monovalent cation, such as sodium and potassium salts.
- suitable monovalent salts include potassium sulfate, and sodium sulfate.
- a variety of different polyphosphates may be used in combination with the monovalent salt for activation of the settable compositions, including polymeric metaphosphate salts, phosphate salts, and combinations thereof.
- polymeric metaphosphate salts that may be used include sodium hexametaphosphate, sodium trimetaphosphate, sodium tetrametaphosphate, sodium pentametaphosphate, sodium heptametaphosphate, sodium octametaphosphate, and combinations thereof.
- a specific example of a suitable set activator comprises a combination of sodium sulfate and sodium hexametaphosphate.
- the activator may be provided and added to the settable compositions as a liquid additive, for example, a liquid additive comprising a monovalent salt, a polyphosphate, and optional ly a dispersant.
- the set activator is typical ly added to the settable compositions prior to introducing the settable compositions into the subterranean formation and/or wel lbore: however, there may be instances where it is necessary to add one or additional set activators to the settable compositions after they have been introduced to the subterranean formation.
- Some embodiments may include a set activator comprising a combination of a monovalent salt and a polyphosphate.
- the monovalent salt and the polyphosphate may be combined prior to their addition to the settable compositions or they may be separately added to the settable compositions.
- the monovalent salt may be any salt that dissociates to form a monovalent cation, such as sodium and potassium salts. Specific examples of suitable monovalent salts include potassium sulfate and sodium sulfate.
- a variety of different polyphosphates may be used in combination with the monovalent salt for activation of the settable compositions, including polymeric metaphosphate salts, phosphate salts, and combinations thereof, for example.
- polymeric metaphosphate salts that may be used include sodium hexametaphosphate, sodium trimetaphosphate, sodium tetrametaphosphate, sodium pentametaphosphate, sodium heptametaphosphate, sodium octametaphosphate, and combinations thereof.
- a specific example of a suitable set activator comprises a combination of sodium sulfate and sodium hexametaphosphate.
- sodium hexametaphosphate is also known in the art to be a strong retarder of Portland cements. Because of the unique chemistry of polyphosphates, polyphosphates may be used as a set activator for embodiments of the settable compositions disclosed herein.
- the ratio of the monovalent salt to the polyphosphate may range, for example, from about 5 : 1 to about 1 :25 or from about 1 : 1 to about 1 : 10.
- Embodiments of the set activator may comprise the monovalent salt and the polyphosphate salt in a ratio (monovalent salt to polyphosphate) ranging between any of and/or including any of about 5 : 1 , 2: 1 , about 1 : 1 , about 1 :2, about 1 :5, about 1 : 10, about 1 :20, or about 1 :25.
- the combination of the monovalent salt and the polyphosphate may be mixed with a dispersant and water to form a liquid additive for activation of a settable composition.
- suitable dispersants include, without limitation, the previously described dispersants, such as sulfonated-formaldehyde-based dispersants and polycarboxylated ether dispersants.
- a commercial dispersant is CFR-3TM dispersant, available from Halliburton Energy Services, Inc.
- a suitable polycarboxylated ether dispersant is Liquiment " 5 14L or 558 1 F dispersants. available from BASF Corporation. Houston. Texas.
- the l iquid additive may function as a set activator. As discussed above, a set activator may also accelerate the setting of the settable composition. The use of a l iquid additive to accelerate a settable composition is dependent upon the compositional makeup of the liquid additive as well as the compositional makeup of the settable compositions. With the benefit of this disclosure, one of ordinary skill in the art should be able to formulate a liquid additive to activate and/or accelerate settable compositions.
- the set activator may be included in the settable compositions in an amount sufficient to induce the settable compositions to set into a hardened mass. I n certain embodiments, the set activator may be included in the settable compositions in an amount in the range of about 0.1 % to about 20% by weight of the pumice. In specific embodiments, the set activator may be present in an amount ranging between any of and/or including any of about 0.1 %, about 1 %, about 5%, about 1 0%, about 15%, or about 20% by weight of the pumice. Additionally, more than one set activator may be used, such that a combination of set activators may be provided to the settable compositions. One of ordinary skill in the art, with the benefit of this disclosure, will recognize the appropriate amount of set activator to include for a chosen application.
- additives suitable for use in subterranean operations also may be included in embodiments of the settable compositions.
- additives include, but are not limited to: weighting agents, lightweight additives, gas-generating additives, mechanical- property-enhancing additives, lost-circulation materials, filtration-control additives, fluid-loss- control additives, defoaming agents, foaming agents, thixotropic additives, and combinations thereof.
- suitable weighting agents include, for example, materials having a specific gravity of 3 or greater, such as barite.
- one or more of these additives may be added to the settable compositions after storing but prior to the placement of the settable compositions into a subterranean formation.
- the settable compositions generally should have a density suitable for a particular application.
- the settable compositions may have a density in the range of from about 4 pounds per gallon ("lb/gal") to about 20 lb/gal.
- the settable compositions may have a density in the range of from about 8 lb/gal to about 1 7 lb/gal .
- Embodiments of the settable compositions may be foamed or unfoamed or may comprise other means to reduce their densities, such as hol low microspheres, low-density elastic beads, or other density-reducing additives known in the art.
- the density may be reduced after storing the composition, but prior to placement in a subterranean formation.
- the settable composition may be characterized by remaining in a pumpable fluid state for an extended period of time.
- the settable compositions When used in subterranean operations, the settable compositions may remain in a pumpable fluid state at downhoie conditions (even after activation) for a period of time from about 1 day to about 7 days or longer. In some embodiments, the settable compositions may remain in a pumpable fluid state for about 1 day, about 2 days, about 3 days, etc.
- the settable compositions may be activated thermally or with a set activator. In embodiments where the settable compositions are activated thermally, the settable compositions are activated by the heat of the subterranean formation in which they are introduced.
- the set activator may be added to the settable compositions prior to pumping the settable compositions into the subterranean formation.
- the thickening time of the settable compositions refers to the measure of time that a settable composition (e.g., a settable spotting composition) remains in pumpable fluid state.
- a settable composition is considered to be in a pumpable fluid state where the fluid has a consistency of less than 70 Bearden units of consistency ("Be"), as measured on a pressurized consistometer in accordance with the procedure for determining cement thickening times set forth in API RP Practice I 0B-2, Recommended Practice for Testing Well Cements, First Edition, July 2005.
- the thickening times described herein may be for any embodiment of the settable compositions used within temperature ranges of about 140°F to about 450°F and for pressures ranging from the ambient pressure of the formation to greater than 15,000 psi.
- embodiments of the settable compositions may be activated (e.g., by combination with an activator) to set into a hardened mass.
- set activator or “activator”, as used herein, refers to an additive that activates a set-delayed or retarded settable composition.
- a set activator may also accelerate the setting of the set-delayed or retarded settable composition.
- embodiments of the settable compositions may be activated to form a hardened mass in a time period in the range of from about 1 day to about 7 days, or longer.
- embodiments of the settable compositions may set to form a hardened mass in about 1 day. about 3 days, about 5 days, about 7 days, or longer.
- the settable compositions may continue to gain compressive strength over time periods exceeding 7 days.
- the settable compositions may set to have a desirable compressive strength after activation. However, the settable compositions should not develop an initial compressive strength of 50 psi for an extended period of time.
- Compressive strength is generally the capacity of a material or structure to w ithstand axially directed pushing forces. The compressive strength may be measured at a specified time after the settable composition has been activated and the resultant composition is maintained under specified temperature and pressure conditions. Compressive strength can be measured by either destructive or non-destructive methods. The destructive method physically tests the strength of treatment fluid samples at various points in time by crushing the samples in a compression-testing machine.
- the compressive strength is calculated from the failure load divided by the cross-sectional area resisting the load and is reported in units of pound-force per square inch (psi).
- Non-destructive methods may employ a UCATM ultrasonic cement analyzer, available from Fann Instrument Company, Houston, TX. Compressive strength values may be determined in accordance with API RP 10B-2, Recommended Practice for Testing Well Cements, First Edition, July 2005.
- the settable composition may be characterized by having an initial set to 50 psi of about 1 day or longer.
- the settable composition may not develop 50 psi of compressive strength when allowed to set at downhole conditions for about 1 day or longer.
- the settable composition may not develop 50 psi of compressive strength for about 1 day, about 2 days, about 5 days, or even longer.
- the compressive strength values may be determined using destructive or non-destructive methods at a temperature ranging from 100°F to 200°F.
- a settable composition may be provided that comprises water, pumice, hydrated lime, a set retarder, and optionally a dispersant.
- the settable composition may be stored, for example, in a vessel or other suitable container.
- the settable composition may be permitted to remain in storage for a desired time period.
- the settable composition may remain in storage for a time period of about 1 day or longer.
- the settable composition may remain in storage for a time period of about 1 day, about 2 days, about 5 days, about 7 days, about 10 days, about 20 days, about 30 days, about 40 days, about 50 days, about 60 days, or longer.
- the settable composition may be activated, for example, by the addition of a set activator, introduced into a subterranean formation, and then allowed to set therein.
- embodiments of the settable compositions may be used in a variety of subterranean operations where it is described for a settable composition to remain pumpable for an extended period of time after placement.
- the settable compositions may be used as settable spotting compositions and in "puddle jobs."
- a settable composition may be provided that comprises water, pumice, hydrated lime, a set retarder, and optionally a set activator.
- the settable compositions may be introduced into a subterranean formation and allowed to set therein.
- the properties of the settable composition when allowed to set in the formation may make it particularly suited for use as a settable spotting composition and/or in puddle jobs.
- the settable composition may remain in a pumpable fluid state for 1 day, 3 days, 5 days, 7 days, or even longer.
- the settable composition may also not develop a compressive strength after introduction into the subterranean formation for a period of 1 day, 3 days, 5 days, 7 days, or even longer.
- the settable composition may have a gel strength of less than about 25 lbs./ ⁇ ⁇ ft. 2 for about 1 day, 3 days, 5 days, 7 days, or even longer and a yield point of less than about 20 lbs./100 ft.
- introducing the settable compositions into a subterranean formation includes introduction into any portion of the subterranean formation, including, without limitation, into a wellbore drilled into the subterranean formation, into a near wellbore region surrounding the wellbore, or into both.
- Embodiments may further include storage of the settable compositions for extended time periods (e.g., about 1 day to about 2 years) and also the activation of the settable compositions by thermal activation or by the addition of a set activator.
- the settable composition may be used as a settable spotting composition in the displacement of a drilling fluid from a wellbore.
- An example method may comprise introducing a settable composition into a wellbore so as to displace at least a portion of a drilling fluid from the wellbore.
- the settable composition may comprise water, pumice, hydrated lime, a set retarder, and optionally a set activator.
- the settable composition may be used to displace the drilling fluid from the wellbore before the drilling fluid has undesirably increased in gel strength. It may be desirable, in some embodiments, for the settable composition to displace the drilling fluid from those portions of the wellbore containing fractures, vugs, and other permeable portions of the wellbore.
- additional steps may include, but are not limited to. introducing a pi pe string into the w el ibore. and introducing a cement composition into the welibore so as to displace at least a portion of the settable from the welibore. Portions of the settable composition may remai n in the welibore. for example, in fractures or other permeable portions of the subterranean formation. Those of ordinary skil l i n the art will appreciate that the cement composition also may displace any remaining dri lling fluid from the welibore. After introduction therein, the cement composition should be al lowed to set in the welibore.
- the settable composition may be used in puddlejobs.
- An example method may comprise introducing a settable composition into the wel ibore and placing it in a puddle at the bottom of the welibore or a puddle formed above a plug (e.g., in surface or near surface applications).
- the settable composition may comprise water, pumice, hydrated lime, a set retarder, and optionally a set activator.
- the settable compositions may remain in a fluid state in a puddle at the bottom of the welibore until a conduit is placed into the welibore and positioned.
- the settable compositions may then set in the annular space between the conduit and the walls of a welibore to form an annular sheath of a hardened mass.
- the hardened mass may form a barrier that prevents the migration of fluids in the weli bore.
- the settable composition may also, for example, support the conduit in the welibore.
- An embodiment comprises a method for introducing a settable composition into a welibore, the method comprising: providing a settable composition comprising pumice, hydrated lime, a set retarder, and water; introducing the settable composition into a welibore; and allowing the settable composition to remain static in the welibore, wherein the settable composition remains in a pumpable fl uid state for a period of about 1 day or longer while static in the welibore.
- An additional embodiment comprises a method for introducing a settable composition into a welibore, the method comprising: providing a settable composition comprising pumice, hydrated lime, a set retarder, and water; introducing the settable composition into the welibore such that the settable composition forms a puddle in the bottom of the welibore; and allowing the settable composition to remain static in the welibore, wherein the settable composition remains in a pumpable fluid state for a period of about 1 day or longer while static in the welibore.
- An additional embodiment comprises a settable composition system for setting a casing comprising: welibore casing disposed within a welibore; a settable composition comprising: water, pumice, hydrated lime, and a set retarder; wherein the settable composition is capable of remaining in a fluid state of less than 70 Be for a time period of about 5 days or longer after the settable composition is introduced into the wellbore: mixing equipment capable of mixing the settable composition; and pumping equipment capable of pumping the settable composition into the wellbore.
- FIG. 1 illustrates surface equipment 5 that may be used in placement of a settable composition in accordance with certain embodiments.
- the surface equipment 5 may include a cementing unit 10, which may include one or more cement trucks.
- the cementing unit 1 0 may include mixing equipment 1 5 and pumping equipment 20 as will be apparent to those of ordinary skill in the art.
- the cementing unit 10 may pump a settable composition 25 (depicted by the arrows) through a feed pipe 30 to a cementing head 35 which conveys the settable composition 25 downhole.
- FIGs. 2A-2D depicts subterranean formation 40 penetrated by wellbore 45 with drilling fluid 50 disposed therein. While the wellbore 45 is shown extending generally vertically into the subterranean formation 40, the principles described herein are also applicable to wellbores that extend at an angle through the subterranean formation 40, such as horizontal and slanted wellbores.
- the wellbore 45 may be drilled into the subterranean formation 40 using any suitable drilling technique. As illustrated, the drilling fluid 50 may be introduced into the wellbore 45 through a drill string and bottom hole assembly (BHA) 55.
- BHA bottom hole assembly
- a settable composition 25 may be run behind the drilling fluid 50, which occupies the lower portion of the drill string and BHA 55.
- FIG. 2B depicts the subterranean formation 40 with the drill string and BHA 55 still placed downhole, and the settable composition 25 circulated through the drill string and BHA 55 such that it exits the drill string and BHA 55 and travels upward through the annulus 70 between the drill string and BHA 55 and the walls 60 of wellbore 45, thus displacing the drilling fluid 50. At least a portion of the displaced drilling fluid 50 may exit the annulus 70 via a flow line 75 and be deposited, for example, in one or more retention pits 80 (e.g., a mud pit), as shown in FIG. 1.
- retention pits 80 e.g., a mud pit
- the drill string and BH A 55 may be circulated and reciprocated in a manner that improves removal of the drill ing fluid 50 trapped along the w ellbore wal ls 60 and in the pockets 65.
- the dril l ing fluid 50 may be displaced by the settable composition 25.
- the dri l l stri ng and BH A 55 may be removed and a casing string 85 may be placed into the wel lbore 45.
- a cement composition 90 may then be run behind the settable composition 25 in the casing string 85, and, as depicted in FIG . 2D, circulated through the casing string 85 such that it exits the bottom of the casing string 85 and travels upward through the annul us 70 between the casing string 85 and the wal ls 60 of the wellbore 45 to the predetermined top-of- cement (TOC) depth.
- TOC top-of- cement
- any of the settable composition 25 that is not displaced and remains on the walls 60 of the wellbore 45 and/or in the pockets 65. will, in time, set into a hardened mass 95, therefore precluding the formation of undesirable channels and pathways through which fluids may migrate.
- FIG. 3 the wellbore 45 is illustrated penetrating subterranean formation 40.
- a casing string 85 may be run into the wellbore 45 to a depth placing the lower end of the casing string 85 to be cemented above the critical interval through which a cement sheath is desired.
- Mounted on the lower end of the casing string 85 may be a float valve 1 00 or any other type of plug (e.g., any sufficient sealing plug and not necessarily a valve).
- the float valve 100 may be a float valve of any type (e.g., a flapper float valve).
- the casing string 85 may have centralizers 105 (e.g., as shown on FIG. 4) along its length to keep the casing string 85 away from the walls 60 of the wellbore 45.
- the settable composition 25 may be pumped and discharged into the lower end of the wellbore 45.
- the settable composition 25 may be discharged into the lower end of the wellbore 45 via a drill string and BHA 55 (e.g., as shown in FIGs. 2A-2B) which may be placed into the wellbore 45 prior to positioning the casing string 85 into the wellbore 45.
- the settable composition 25 may be discharged into the lower end of the wellbore 45 via a drill string and BHA 55 (or other suitable conduit) that is run through the casing string 85 such that the drill string and BHA 55 exits through the lower end of the casing string 85 via the float valve 100.
- the volume of the settable composition 25 pumped into the wellbore 45 may depend on a number of factors, including the length of the interval needed to be set.
- the settable composition 25 may remain in a pumpable fluid state (i.e., the settable composition has a consistency of less than 70 Be) for a period of 1 day, 3 days, 7 day, or longer.
- the settable composition 25 should not set in the wellbore 45 unti l al l operations requiring the settable composition 25 to remain in a pumpable fluid state have been completed. It is therefore beneficial to have an accurate estimate of the duration of such operations prior to the formulation of the settable composition 25.
- the casing string 85 may be lowered to the desired depth within the wellbore 45. As illustrated, the casing string 85 is lowered into settable composition 25 in the lower end of the wellbore 45.
- the float valve 1 00 should prevent entry of the settable composition 25 into the casing string 85.
- the settable composition 25 may be displaced from the middle of the wellbore 45 by the casing string 85 with the annulus 70 surrounding the casing string 85 containing the settable composition 25.
- the settable composition 25 may be forced up the annulus 70 causing the settable composition 25, for example, to displace any other fluids (e.g., drilling fluid 50 (not shown) and/or other fluids such as spacer fluids, displacement fluids, cleaning fluids, and the like) that may have remained in the wellbore 45.
- the casing string 85 may then be suspended in the wellbore 45 until the settable composition 25 disposed in the annulus 70 has set.
- the exemplary settable compositions disclosed herein may directly or indirectly affect one or more components or pieces of equipment associated with the preparation, delivery, recapture, recycling, reuse, and/or disposal of the disclosed settable compositions.
- the disclosed settable compositions may directly or indirectly affect one or more mixers, related mixing equipment, mud pits, storage facilities or units, composition separators, heat exchangers, sensors, gauges, pumps, compressors, and the like used generate, store, monitor, regulate, and/or recondition the exemplary settable compositions.
- the disclosed settable compositions may also directly or indirectly affect any transport or delivery equipment used to convey the settable compositions to a well site or downhole such as, for example, any transport vessels, conduits, pipelines, trucks, tubulars, and/or pipes used to compositionally move the settable compositions from one location to another, any pumps, compressors, or motors (e.g., topside or downhole) used to drive the settable compositions into motion, any valves or related joints used to regulate the pressure or flow rate of the settable compositions, and any sensors (i.e., pressure and temperature), gauges, and/or combinations thereof, and the like.
- any transport or delivery equipment used to convey the settable compositions to a well site or downhole
- any transport vessels, conduits, pipelines, trucks, tubulars, and/or pipes used to compositionally move the settable compositions from one location to another
- any pumps, compressors, or motors e.g., topside or downhole
- any valves or related joints used to regulate the pressure or flow rate of the
- the disclosed settable compositions may also directly or indirectly affect the various downhole equipment and tools that may come into contact with the settable compositions such as, but not limited to, wellbore casing, wellbore liner, completion string, insert strings, drill string, coiled tubing, slickline, wireline, drill pipe, drill collars, mud motors, downhole motors and/or pumps, cement pumps, surface-mounted motors and/or pumps, centralizers. turbol izers. scratchers, floats (e.g.. shoes, col lars, valves, etc.). logging tools and related telemetn equipment, actuators (e.g.. electromechanical devices, hydromechanical devices, etc.).
- actuators e.g. electromechanical devices, hydromechanical devices, etc.
- flow control devices e.g., inflow control devices, autonomous inflow control devices, outflow control devices, etc.
- coupl ings e.g., electro-hydraulic wet connect, dry connect, inductive coupler, etc.
- control lines e.g., electrical, fiber optic, hydraulic, etc.
- surveillance lines drill bits and reamers, sensors or distributed sensors, downhole heat exchangers, valves and corresponding actuation devices, tool seals, packers, cement plugs, bridge plugs, and other wellbore isolation devices, or components, and the like.
- the viscosifier was SA- 101 5TM suspending agent available from Halliburton Energy Services, Inc., Houston, TX.
- the accelerator was an aqueous solution of sodium hexametaphosphate (SHMP) and sodium sulfate in a 1 : 1 ratio (6% activity).
- SHMP sodium hexametaphosphate
- the UCA test ran for 1 7 days.
- the destructive compressive strength was measured by using a mechanical press to crush the samples in accordance with the procedure set forth in API RP Practice 10B-2, Recommended Practice for Testing Well Cements.
- the rush strength was measured as 473.7 psi.
- Table 2 The results of the UCA compressive strength testing are presented in Table 2 below.
- the composition did not gain compressive strength for approximately 60 hours.
- Sample I reached initial set after 121 hours and achieved a compressive strength of 500 psi in over 41 1 hours. This indicates that the composition remained in a fluid state for at least 60 hours and did not reach a reasonable compressive strength until after 121 hours.
- the composition continued to gain compressive strength until the text was terminated.
- this sample was subjected to a static gel strength analysis in accordance with the procedure set forth in API RP-l Ob- 6/1 SO 10426-6, Recommended Practice on Determining the Static Gel Strength of Cement Formulations at 80 °F, 3000 psi, which are the same parameters as the UCA analysis.
- the sample exhibited zero gel time of greater than 13 days.
- Samples l l-VI were prepared and subjected to thickening time ( pump time) tests on a high-pressure high-temperature consistometer.
- the compositional makeup of Samples l l-VI are presented in Table 3 below.
- the cement retarder was M icro Matrix " Cement Retarder avai lable from Hal l iburton Energy Services. I nc., Houston, TX.
- the co-retarder was H R*-5 available from Hall iburton Energy Services. I nc.. Houston. TX.
- the dispersant was Liquiment 5581 F dispersant available from BASF. Florham Park. New Jersey .
- the viscosifier was SA- 101 5 1 " suspending agent available from Halliburton Energy Services, Inc., Houston, TX.
- the accelerator was an CaCh.
- Sample VII was prepared to build off the favorable results of Sample IV.
- Sample VI I was prepared using additional retarder and dispersant.
- the compositional makeup of Sample VI I is presented in Table 5 below.
- the weighting agent was Micromax ® FF weight additive available from Micromax ® FF weight additive available from Micromax ® FF weight additive.
- the cement retarder was Micro Matrix ® Cement Retarder available from Halliburton Energy Services, Inc., Houston, TX.
- the co-retarder was
- the viscosifier was SA- 10I 5TM suspending agent available from Halliburton Energy Services, Inc., Houston, TX.
- the accelerator was CaCb.
- the thickening time test was conducted at 140 °F and 3000 psi.
- the samples were poured into 2 inch by 4 inch brass cy linders and cured in a water batch at 1 40 °F at atmospheric pressure for 7 days. Additional ly, the samples were poured into 1 inch by 2 inch brass cylinders and cured in a water batch at 140 °F at 3000 psi for 7 days.
- the destructive compressive strength was measured by using a mechanical press to crush the samples in accordance with the procedure set forth in API RP Practice 10B-2. Recommended Practice for Testing Well Cements. Then the destructive compressive strength was measured by using a mechanical press to crush the samples in accordance with the procedure set forth in API RP Practice 10B-2, Recommended Practice for Testing Well Cements. The results of this test are set forth in Table 6 below.
- Samples VII1-XVI were prepared to test the settable compositions under the high- temperature, high-pressure conditions of 350 °F and 1 5,000 psi using a high-temperature high- pressure consistometer.
- the compositional makeup of Samples VIII-XVI are presented in Table 7 below.
- the cement retarder was M icro Matrix " Cement Retarder avai lable from Hall iburton Energy Services. I nc.. Houston, TX .
- the co-retarder was H R " -5 available from Hal l iburton Energy Services. I nc.. Houston. TX.
- the dispersant was Liquiment 558 I F dispersant available from BASF. Florham Park, New Jersey.
- the viscosifier was SA- 101 5TM suspending agent available from Halliburton Energy Services, Inc., Houston, TX.
- the thickening time and the heat of hydration were determined using a high- temperature high-pressure consistometer in accordance w ith API RP Practice 10B-2, Recommended Practice for Testing Well Cements. The test was conducted at 350 °F and 1 5,000 psi w ith a 28 minute ramp time. The heat of hydration was determined through inspection of the thickening time test chart. The results of this test are set forth in Table 8 below.
- FIG . 5A provides an example of "right-angle" set profile using Sample XVI as an example.
- FIG. 5B provides an example of gelation set profile using Sample VI I I as an example.
- compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of or “consist of the various components and steps.
- indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the element that it introduces.
- ranges from any lower limit may be combined with any upper limit to recite a range not explicitly recited, as well as, ranges from any lower limit may be combined with any other lower limit to recite a range not explicitly recited, in the same way, ranges from any upper limit may be combined with any other upper limit to recite a range not explicitly recited.
- any numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range are specifically disclosed.
- every range of values (of the form, "from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b") disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values even if not explicitly recited.
- every point or individual value may serve as its own lower or upper limit combined with any other point or individual value or any other lower or upper limit, to recite a range not explicitly recited.
Abstract
Description
Claims
Priority Applications (7)
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JP2016548639A JP6275855B2 (en) | 2014-02-28 | 2015-02-25 | Curable composition and method of use |
AU2015223141A AU2015223141B2 (en) | 2014-02-28 | 2015-02-25 | Settable compositions and methods of use |
CN201580005840.XA CN105934558A (en) | 2014-02-28 | 2015-02-25 | Settable compositions and methods of use |
CA2936003A CA2936003C (en) | 2014-02-28 | 2015-02-25 | Settable compositions and methods of use |
GB1608419.6A GB2537518B (en) | 2014-02-28 | 2015-02-25 | Settable compositions and methods of use |
MX2016009580A MX2016009580A (en) | 2014-02-28 | 2015-02-25 | Settable compositions and methods of use. |
NO20160830A NO20160830A1 (en) | 2014-02-28 | 2016-05-18 | Settable compositions and methods of use |
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US14/194,125 US9534165B2 (en) | 2012-03-09 | 2014-02-28 | Settable compositions and methods of use |
US14/194,125 | 2014-02-28 |
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CN (1) | CN105934558A (en) |
AR (1) | AR099607A1 (en) |
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CN108410438A (en) * | 2018-04-16 | 2018-08-17 | 中国石油集团川庆钻探工程有限公司 | One kind can bore brittleness gel partition working solution and preparation method thereof |
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US20060249054A1 (en) * | 2005-05-05 | 2006-11-09 | Halliburton Energy Services, Inc. | Set-delayed cement compositions comprising hydrated lime and silica and methods of cementing in subterranean formations |
US20100258312A1 (en) * | 2005-09-09 | 2010-10-14 | Halliburton Energy Services, Inc. | Methods of Plugging and Abandoning a Well Using Compositions Comprising Cement Kiln Dust and Pumicite |
US8281859B2 (en) * | 2005-09-09 | 2012-10-09 | Halliburton Energy Services Inc. | Methods and compositions comprising cement kiln dust having an altered particle size |
US20140000893A1 (en) * | 2012-03-09 | 2014-01-02 | Halliburton Energy Services, Inc. | Set-Delayed Cement Compositions Comprising Pumice and Associated Methods |
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US5447197A (en) * | 1994-01-25 | 1995-09-05 | Bj Services Company | Storable liquid cementitious slurries for cementing oil and gas wells |
US7111684B2 (en) * | 2004-09-14 | 2006-09-26 | Halliburton Energy Services, Inc. | Subterranean fluids having improved environmental characteristics and methods of using these fluids in subterranean formations |
US8672028B2 (en) * | 2010-12-21 | 2014-03-18 | Halliburton Energy Services, Inc. | Settable compositions comprising interground perlite and hydraulic cement |
US7743828B2 (en) * | 2005-09-09 | 2010-06-29 | Halliburton Energy Services, Inc. | Methods of cementing in subterranean formations using cement kiln cement kiln dust in compositions having reduced Portland cement content |
US7199086B1 (en) * | 2005-11-10 | 2007-04-03 | Halliburton Energy Services, Inc. | Settable spotting compositions comprising cement kiln dust |
US7284609B2 (en) * | 2005-11-10 | 2007-10-23 | Halliburton Energy Services, Inc. | Methods of using settable spotting compositions comprising cement kiln dust |
US9284224B2 (en) * | 2011-05-13 | 2016-03-15 | Halliburton Energy Services, Inc. | Cement compositions and methods of using the same |
US8851173B2 (en) * | 2012-03-09 | 2014-10-07 | Halliburton Energy Services, Inc. | Set-delayed cement compositions comprising pumice and associated methods |
-
2015
- 2015-02-25 CA CA2936003A patent/CA2936003C/en active Active
- 2015-02-25 WO PCT/US2015/017564 patent/WO2015130815A1/en active Application Filing
- 2015-02-25 JP JP2016548639A patent/JP6275855B2/en not_active Expired - Fee Related
- 2015-02-25 MX MX2016009580A patent/MX2016009580A/en unknown
- 2015-02-25 AU AU2015223141A patent/AU2015223141B2/en active Active
- 2015-02-25 GB GB1608419.6A patent/GB2537518B/en active Active
- 2015-02-25 CN CN201580005840.XA patent/CN105934558A/en active Pending
- 2015-02-27 AR ARP150100614A patent/AR099607A1/en active IP Right Grant
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Patent Citations (5)
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US20060249289A1 (en) * | 2005-05-05 | 2006-11-09 | Halliburton Energy Services, Inc. | Set-delayed cement compositions comprising hydrated lime and silica and methods of cementing in subterranean formations |
US20060249054A1 (en) * | 2005-05-05 | 2006-11-09 | Halliburton Energy Services, Inc. | Set-delayed cement compositions comprising hydrated lime and silica and methods of cementing in subterranean formations |
US20100258312A1 (en) * | 2005-09-09 | 2010-10-14 | Halliburton Energy Services, Inc. | Methods of Plugging and Abandoning a Well Using Compositions Comprising Cement Kiln Dust and Pumicite |
US8281859B2 (en) * | 2005-09-09 | 2012-10-09 | Halliburton Energy Services Inc. | Methods and compositions comprising cement kiln dust having an altered particle size |
US20140000893A1 (en) * | 2012-03-09 | 2014-01-02 | Halliburton Energy Services, Inc. | Set-Delayed Cement Compositions Comprising Pumice and Associated Methods |
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GB2537518A (en) | 2016-10-19 |
MX2016009580A (en) | 2016-10-13 |
JP2017510669A (en) | 2017-04-13 |
JP6275855B2 (en) | 2018-02-07 |
AU2015223141A1 (en) | 2016-06-02 |
GB2537518B (en) | 2017-08-23 |
CA2936003C (en) | 2018-05-08 |
CN105934558A (en) | 2016-09-07 |
CA2936003A1 (en) | 2015-09-03 |
GB201608419D0 (en) | 2016-06-29 |
AR099607A1 (en) | 2016-08-03 |
AU2015223141B2 (en) | 2017-03-16 |
NO20160830A1 (en) | 2016-05-18 |
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