WO2015080977A1 - Placing a fluid comprising kiln dust in a wellbore through a bottom hole assembly - Google Patents
Placing a fluid comprising kiln dust in a wellbore through a bottom hole assembly Download PDFInfo
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- WO2015080977A1 WO2015080977A1 PCT/US2014/066908 US2014066908W WO2015080977A1 WO 2015080977 A1 WO2015080977 A1 WO 2015080977A1 US 2014066908 W US2014066908 W US 2014066908W WO 2015080977 A1 WO2015080977 A1 WO 2015080977A1
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- Prior art keywords
- wellbore
- fluid
- kiln dust
- treatment fluid
- cement
- Prior art date
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Classifications
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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
- C09K8/02—Well-drilling compositions
- C09K8/04—Aqueous well-drilling 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
- C09K8/42—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
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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
- C09K8/02—Well-drilling 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
- C09K8/40—Spacer compositions, e.g. compositions used to separate well-drilling from cementing masses
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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
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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
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
Definitions
- Embodiments relate to subterranean operations and, in some embodiments, to introduction of fluids comprising kiln dust into a wellbore through a bottom hole assembly.
- Wells are generally drilled into the ground to recover natural deposits of hydrocarbons and other desirable materials trapped in geological formations in the Earth's crust.
- Wells may be drilled by rotating a drill bit which is located on a bottom hole assembly at a distal end of a drill string.
- a drill bit which is located on a bottom hole assembly at a distal end of a drill string.
- a wellbore is drilled to a desired depth and then the wellbore is lined with a larger-diameter pipe, typically referred to as a casing.
- the drill string and drill bit Prior to inserting the casing and cementing it in place, the drill string and drill bit are removed from the wellbore. After the casing has been cemented in place, drilling is continued.
- casing drilling a technique referred to as "casing drilling” in which a casing is used in place of a drilling string. Similar to a drill string, the drill bit is connected to a distal end of the casing, and the casing is used to transmit rotational and axial forces to the drill bit. When the wellbore has been drilled to a desired depth, the casing may be cemented in place. In some instances, cement compositions and associated spacer fluids used in the cementing operation are placed into the wellbore through the bottom hole assembly. Casing drilling enables the well to be drilled and cased without the delays associated with removal of the drill bit and drill string from the wellbore.
- a number of different fluids may be used in drilling and casing the wellbore.
- a drilling fluid may be pumped down through the drill string (or casing), out through the drill bit, and returned to the surface in the annulus between the drill string and the wellbore wall.
- the drilling fluid can act to lubricate and cool the drill bit as well as carry drill cuttings back to the surface.
- Spacer fluids can also be used in these operations.
- a spacer fluid may be used to displace drilling fluids from the wellbore before introduction of another fluid, such as a cement composition.
- cement compositions may be used to cement the casing in the wellbore.
- the cement composition may be allowed to set in the annulus between the casing and the wellbore wall, thereby forming an annular sheath of hardened cement (e.g., a cement sheath) that should support and position the pipe string in the wellbore and bond the exterior surface of the pipe string to the walls of the wellbore.
- a cement sheath e.g., a cement sheath
- FIG. 1 is a schematic view of an example system that may be used for casing while drilling in accordance with various embodiments.
- FIG. 2 is a schematic view of an example system that may be used for casing while directional drilling in accordance with various embodiments.
- FIGS. 3 and 4 are schematic views showing displacement of the drilling fluid with placement of the spacer fluid and cement composition through a bottom hole assembly in accordance with various embodiments.
- FIG. 5 is a schematic view showing equipment for placement of a cement composition into a wellbore in accordance with various embodiments.
- FIG. 6 is a graph showing measured static gel strength values at various temperature and pressure readings as a factor of time for an example treatment fluid.
- FIG. 7 is a graph showing measured static gel strength values at various temperature and pressure readings as a factor of time for an example treatment fluid.
- Embodiments relate to subterranean operations and, in some embodiments, to introduction of a treatment fluid comprising kiln dust into a wellbore through a bottom hole assembly.
- the bottom hole assembly may be attached to a tubular, such as a drill pipe and/or a casing.
- the treatment fluid may be used in a casing drilling operation, wherein the treatment fluid may be introduced into a wellbore through a bottom hole assembly that is attached to a distal end of a casing.
- the treatment fluid may be introduced through a drill bit at a distal end of the bottom hole assembly.
- treatment fluid does not imply any particular action by the fluid or any component thereof. Treatment fluids may be used, for example, for drilling, completion, production, work over, or in any way to prepare a wellbore and/or well equipment for recovery of materials residing in a subterranean formation penetrated by the wellbore.
- the casing drilling system 100 may include a drilling platform 102 that supports a derrick 104 having a traveling block 106 for raising and lowering a casing 108.
- the casing 108 may be generally tubular and comprise a string of tubulars, which may include conductor casing, surface casing, intermediate casing, production casing, or a production liner. Casing collars or other suitable connectors may be used to couple joints of tubulars to form the casing 108.
- completion equipment may be attached to the casing 108.
- the individual components of the casing 108 are not shown on FIG. 1 .
- the casing 108 is generally a larger diameter tubular than would typically be used for drilling.
- a kelly 1 10 may support the casing 108 as it is lowered through a rotary table 1 12.
- a bottom hole assembly 1 14 may be coupled to the distal end of the casing 108.
- the bottom hole assembly 1 14 may be a retrievable or non-retrievable bottom hole assembly.
- the bottom hole assembly 1 14 may include a drill bit 1 16 on its distal end and may be driven either by a downhole motor and/or via rotation of the casing 108 from the well surface. As the drill bit 1 16 rotates, it creates a wellbore 1 18 that penetrates various subterranean formations 120.
- the bottom hole assembly 1 14 further includes an underreamer 122, which may be used to enlarge the wellbore 1 18 beyond the diameter of the drill bit 1 16, for example.
- the underreamer 122 may be incorporated into the drill bit 1 16, incorporated with a lower end of the casing 108, or be a separate component attached to the drill bit 1 16. It should be noted that while FIG. 1 generally depicts a casing drilling system 100 being land based, those skilled in the art will readily recognize that the principles described herein are equally applicable to subsea drilling operations that employ floating or sea-based platforms and rigs, without departing from the scope of the disclosure.
- a pump 124 may circulate the drilling fluid 126 through a feed pipe 128 and to the kelly 1 10, which conveys the drilling fluid 126 downhole through the interior of the casing 108 and through one or more orifices in the drill bit 1 16.
- the drilling fluid 126 may then be circulated back to the surface via an annulus 130 defined between the casing 108 and the walls of the wellbore 1 18.
- the recirculated or spent drilling fluid 126 exits the annulus 130 and may be conveyed to one or more fluid processing unit(s) 132 via an interconnecting flow line 134.
- a "cleaned" drilling fluid 126 may be deposited into a nearby retention pit 136 (e.g., a mud pit). While illustrated as being arranged at the outlet of the wellbore 1 18 via the annulus 130, those skilled in the art will readily appreciate that the fluid processing unit(s) 132 may be arranged at any other location in the casing drilling system 100 to facilitate its proper function, without departing from the scope of the scope of the disclosure.
- embodiments may include directional casing drilling.
- Directional drilling generally refers to the intentional deviation of the wellbore 1 18.
- Directional drilling may enable horizontal drilling through one or more subterranean formations 120.
- directional casing drilling may be used to create wellbore 1 18 having a vertical upper section 136 and a slanted lower section 138. Any suitable technique may be used for creation of the slanted lower section 138 that is non-vertical.
- the bottom hole assembly 1 14 used in directional casing drilling may be a rotatory steerable system that allows directional control while rotating.
- the drilling fluid 126 may be displaced from the wellbore 1 18 by a spacer fluid 140 in accordance with certain embodiments.
- the spacer fluid 140 may be a treatment fluid comprising kiln dust and water.
- the spacer fluid 140 may also remove the drilling fluid, dehydrated/gelled drilling fluid, and/or filter cake solids from the wellbore 1 18 in advance of the cement composition 142.
- Embodiments of the spacer fluid 140 may improve the efficiency of the removal of these and other compositions from the wellbore 1 18. Removal of these compositions from the wellbore 1 18 may enhance bonding of the cement composition 142 to surfaces in the wellbore 1 1 8.
- the spacer fluid 140 comprising kiln dust and water may be characterized by having a higher yield point than the drilling fluid 126 at 80°F. In further embodiments, the spacer fluid 140 comprising kiln dust and water may be characterized by having a higher yield point than the drilling fluid 126 at 130°F. In yet further embodiments, the spacer fluid 140 comprising kiln dust and water may be characterized by having a higher yield point than the drilling fluid 126 at 180°F.
- the spacer fluid 140 may be pumped down through the casing 108, out through the bottom hole assembly 1 14, and into the annulus 130.
- the spacer fluid 140 may be introduced into the annulus 130 through the drill bit 1 16 on the bottom hole assembly 1 14.
- the spacer fluid 140 may also separate the drilling fluid 126 from a cement composition 142.
- the cement composition 142 may be introduced into the wellbore 1 18 behind the spacer fluid 140 to cement the casing 108 into the wellbore 1 1 8.
- the cement composition 142 may also be pumped down through the casing 108, out through the bottom hole assembly 1 14, and into the annulus 130.
- the cement composition 142 may be a treatment fluid that comprises kiln dust and water.
- both the spacer fluid 140 and the cement composition 142 may comprise kiln dust.
- either the spacer fluid 140 or cement composition 142 may comprise kiln dust.
- at least a portion of used and/or unused kiln dust containing spacer fluid 140 may be included in the cement composition 142 that is placed into the wellbore 1 18 and allowed to set.
- the spacer fluid 140 and/or cement composition 142 comprising kiln dust may also comprise one or more additional additives in various concentrations and combinations.
- the spacer fluid 140 and cement composition 142 may be disposed in the annulus 130 between the casing 108 and walls of the wellbore 1 18.
- the cement composition 142 may be allowed to consolidate in the annulus 130. More particularly, the cement composition may be allowed to set in the annulus 130 to form an annular sheath of hardened cement.
- the annular sheath may form a barrier that prevents the migration of fluids in the wellbore 1 18.
- the annular sheath may also, for example, support the casing 108 in the wellbore 1 18.
- the spacer fluid 142 may also remain in the annulus 130.
- the remaining portion of the spacer fluid 142 may consolidate in the annulus 130.
- the spacer fluid may set and harden to gain compressive strength by reaction of the kiln dust in the water.
- the spacer fluid 142 after consolidation may prevent the migration of fluids in the wellbore 1 18 and also support the casing 108 in the wellbore 1 18.
- a cementing unit 144 is shown that may be used in the placement of the cement composition 142 into the wellbore 1 18 in accordance with certain embodiments. While not shown, the cementing unit 144 may also be used in placement of the spacer fluid 140 into the wellbore 1 18. As will be apparent to those of ordinary skill in the art, the cementing unit 144 may include mixing equipment, such jet mixers, re-circulating mixers, or batch mixers. In some embodiments, a jet mixer may be used, for example, to continuously mix the components of the spacer fluid 140 and/or the cement composition 142 as it is being pumped to the wellbore 1 18.
- the cementing unit 144 may include one or more cement trucks, which include mixing and pumping equipment. As illustrated, the cementing unit 144 may pump the cement composition 142 through a feed pipe 146 and to a cementing head 148 which conveys the cement composition 142 into the wellbore 1 18. As further illustrated, fluids (e.g., the spacer fluid 140) returned to the surface in the annulus 130 may deposited, for example, in the spacer retention pit 1 50 via the flow line 134.
- fluids e.g., the spacer fluid 140
- the exemplary treatment fluids 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 treatment fluids.
- the disclosed treatment fluids may directly or indirectly affect one or more mixers, related mixing equipment, mud pits (e.g., retention pit 136, spacer retention pit 150), 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 treatment fluids.
- the disclosed treatment fluids may also directly or indirectly affect any transport or delivery equipment used to convey the treatment fluids 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 treatment fluids from one location to another, any pumps, compressors, or motors (e.g., topside or downhole) used to drive the treatment fluids into motion, any valves or related joints used to regulate the pressure or flow rate of the treatment fluids, 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 treatment fluids to a well site or downhole
- any transport vessels, conduits, pipelines, trucks, tubulars, and/or pipes used to compositionally move the treatment fluids 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 treatment fluids
- sensors
- the disclosed treatment fluids may also directly or indirectly affect the various downhole equipment and tools that may come into contact with the treatment fluids such as, but not limited to, wellbore casing (e.g., casing 108), 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, turbolizers, scratchers, floats (e.g., shoes, collars, valves, etc.), logging tools and related telemetry equipment, actuators (e.g., electromechanical devices, hydromechanical devices, etc.), sliding sleeves, production sleeves, plugs, screens, filters, flow control devices (e.g., inflow control devices, autonomous inflow control devices, outflow control devices, etc.), couplings (e.g., electro-hydraulic wet connect, dry connect, inductive coupler, etc.), control lines (e.g., electrical
- Embodiments of the treatment fluids may comprise kiln dust and water.
- the treatment fluids may consolidate when left in a wellbore.
- the treatment fluids may set and harden to gain compressive strength by reaction of the kiln dust in the water.
- the treatment fluids may be foamed.
- the foamed treatment fluids may comprise water, kiln dust, a foaming agent, and a gas.
- a foamed treatment fluid may be used, for example, where it is desired for the fluid to be lightweight and not exert excessive force on subterranean formations 120 penetrated by the wellbore 1 18.
- Embodiments of the treatment fluids may further comprise fly ash, barite, pumicite, a free water control additive, or a combination thereof.
- the treatment fluid may be a spacer fluid 140 that displaces a first fluid (e.g., a drilling fluid 126) from the wellbore 1 18.
- the spacer fluid 140 may have a higher yield point than the first fluid.
- the treatment fluid may be a cement composition 142 that is used in cementing the casing 108 in the wellbore 1 18.
- Embodiment may further comprise using a treatment fluid comprising the kiln dust in drilling the wellbore 1 18.
- the treatment fluid may be circulated past the drill bit 1 16 to carry drill cuttings back to the surface.
- the treatment fluids generally should have a density suitable for a particular application as desired by those of ordinary skill in the art, with the benefit of this disclosure.
- the treatment fluids may have a density in the range of from about 4 pounds per gallon ("ppg") to about 24 ppg.
- the treatment fluids may have a density in the range of about 4 ppg to about 17 ppg.
- the treatment fluids may have a density in the range of about 8 ppg to about 13 ppg.
- Embodiments of the treatment fluids may be foamed or unfoamed or comprise other means to reduce their densities known in the art, such as lightweight additives. Those of ordinary skill in the art, with the benefit of this disclosure, should recognize the appropriate density for a particular application.
- Kiln dust refers to a solid material generated as a by-product of the heating of certain materials in kilns.
- the term "kiln dust” as used herein is intended to include kiln dust made as described herein and equivalent forms of kiln dust.
- Kiln dust typically exhibits cementitious properties in that it can set and harden in the presence of water.
- suitable kiln dusts include cement kiln dust, lime kiln dust, and combinations thereof.
- cement kiln dust may be generated as a by-product of cement production that is removed from the gas stream and collected, for example, in a dust collector.
- cement kiln dust generally may comprise a variety of oxides, such as S1O2, A I 2O3, Fe20.-s, CaO, gO, SO3, Na 2 0, and K 2 O.
- lime kiln dust which may be generated as a by-product of the calcination of lime.
- the chemical analysis of lime kiln dust from various lime manufacturers varies depending on a number of factors, including the particular limestone or dolomitic limestone feed, the type of kiln, the mode of operation of the kiln, the efficiencies of the lime production operation, and the associated dust collection systems.
- Lime kiln dust generally may comprise varying amounts of free lime and free magnesium, lime stone, and/or dolomitic limestone and a variety of oxides, such as S1O2, A 12 ⁇ 3, Fe20s, CaO, MgO, SO3, Na20, and K2O, and other components, such as chlorides.
- the kiln dust may be included in embodiments of the treatment fluids as a rheology modifier.
- using the kiln dust in various embodiments can provide treatment fluids having rheology suitable for a particular application. Desirable rheology may be advantageous to provide a treatment fluid that is effective for drilling fluid displacement, for example, in spacer fluid embodiments.
- the kiln dust can be used to provide a treatment fluid with a low degree of thermal thinning.
- the treatment fluid may even have a yield point that increases at elevated temperatures, such as those encountered downhole.
- the kiln dust may be included in the spacer fluids in an amount sufficient to provide, for example, the desired rheological properties.
- concentration of kiln dust may also be selected to provide a low cost replacement for higher cost additives, such as Portland cement, that may typically be included in a particular treatment fluid.
- the kiln dust may be present in a treatment fluid in an amount in the range of from about 1 % to about 65% by weight of the treatment fluid (e.g., about 1 %, about 5%, about 10%, about 15%, about 20%, about 25%, about 30%, about 35%, about 40%, about 45%, about 50%, about 55%, about 60%, about 65%, etc.).
- the kiln dust may be present in the treatment fluid in an amount in the range of from about 5% to about 60% by weight of the treatment fluid. In some embodiments, the kiln dust may be present in an amount in the range of from about 20% to about 35% by weight of the treatment fluid. Alternatively, the amount of kiln dust may be expressed by weight of cementitious components ("bwocc"). As used herein, the term “by weight of cementitious components” or "bwocc” refers to the amount of a component, such as kiln dust, relative to the overall amount of cementitious components used in preparation of the treatment fluid.
- Cementitious components include those components or combinations of components of the treatment fluid that set, or otherwise harden, to develop compressive strength, including, for example, kiln dust, hydraulic cement, fly ash, hydrated lime, and the like.
- the kiln dust may be present in an amount in a range of from about 1 % to 100% bwocc. (e.g., about 1 %, about 5%, about 10%, about 20%, about 30%, about 40%, about 50%, about 60%, about 70%, about 80%, about 90%, 100%, etc.).
- the kiln dust may be present in an amount in the range of from about 50% to 100% and, alternatively, from about 80% to 100% bwocc.
- the water used in an embodiment of the treatment fluids may include, for example, freshwater, saltwater (e.g., water containing one or more salts dissolved therein), brine (e.g., saturated saltwater produced from a subterranean formations), seawater, or any combination thereof.
- the water may be from any source, provided that the water does not contain an excess of compounds that may undesirably affect other components in the treatment fluid.
- the water may be included in an amount sufficient to form a pumpable fluid.
- the water may be included in the treatment fluids in an amount in a range of from about 40% to about 200% bwocc. In some embodiments, the water may be included in an amount in a range of from about 40% to about 150% bwocc.
- embodiments of the treatment fluids may further comprise fly ash.
- fly ashes may be suitable, including fly ash classified as Class C or Class F fly ash according to American Petroleum Institute, API Specification for Materials and Testing for Well Cements, API Specification 10, Fifth Ed., July 1 , 1990.
- Suitable examples of fly ash include, but are not limited to, POZMIX ® A cement additive, commercially available from Halliburton Energy Services, Inc., Duncan, Oklahoma. Where used, the fly ash generally may be included in the treatment fluids in an amount desired for a particular application.
- the fly ash may be present in an amount in a range of from about 1 % to about 99% bwocc (e.g., about 1 %, about 5%, about 10%, about 20%, about 30%, about 40%, about 50%, about 60%, about 70%, about 80%, about 90%, about 99%, etc.). In some embodiments, the fly ash may be present in an amount in the range of from about 1 % to about 20% and, alternatively, from about 1% to about 10% bwocc.
- the treatment fluids may further comprise barite.
- the barite may be sized barite.
- Sized barite generally refers to barite that has been separated, sieved, ground, or otherwise sized to produce barite having a desired particle size.
- the barite may be sized to produce barite having a particle size less than about 200 microns in size.
- the barite generally may be included in the treatment fluids in an amount desired for a particular application.
- the barite may be present in an amount in a range of from about 1 % to about 99% bwocc (e.g., about 1 %, about 5%, about 10%, about 20%, about 30%, about 40%, about 50%, about 60%, about 70%, about 80%, about 90%, about 99%, etc.). In some embodiments, the barite may be present in an amount in the range of from about 1 % to about 20% and, alternatively, from about 1% to about 10% bwocc.
- embodiments of the treatment fluids may further comprise pumicite.
- pumicite is a volcanic rock that may exhibits cementitious properties, in that it may set and harden in the presence of hydrated lime and water. Hydrated lime may be used in combination with the pumicite, in some embodiments.
- the pumicite generally may be included in the treatment fluids in an amount desired for a particular application.
- the pumicite may be present in an amount in a range of from about 1 % to about 99% bwocc (e.g., about 1 %, about 5%, about 10%, about 20%, about 30%, about 40%, about 50%, about 60%, about 70%, about 80%, about 90%, about 99%, etc.).
- the pumicite may be present in an amount in the range of from about 1% to about 20% and, alternatively, from about 1 % to about 10% bwocc.
- embodiments of the treatment fluids may further comprise a free water control additive.
- a free water control additive refers to an additive included in a liquid for, among other things, reducing (or preventing) the presence of free water in the liquid. Free water control additives may also reduce (or prevent) the settling of solids.
- suitable free water control additives include, but are not limited to, bentonite, amorphous silica, hydroxyethyl cellulose, and combinations thereof.
- An example of a suitable free water control additive is SA-1015TM suspending agent, available from Halliburton Energy Services, Inc.
- Another example of a suitable free water control additive is WG-17TM solid additive, available from Halliburton Energy Services, Inc.
- the free water control additive may be provided as a dry solid in some embodiments. Where used, the free water control additive may be present in an amount in the range of from about 0.1 % to about 16% bwocc, for example. In alternative embodiments, the free water control additive may be present in an amount in the range of from about 0.1% to about 2% bwocc.
- the treatment fluids may further comprise a lightweight additive.
- the lightweight additive may be included to reduce the density of embodiments of the treatment fluids.
- the lightweight additive may be used to form a treatment fluid, for example, having a density of less than about 13 ppg.
- the lightweight additive typically may have a specific gravity of less than about 2.0.
- suitable lightweight additives may include sodium silicate, hollow microspheres, gilsonite, perlite, and combinations thereof.
- An example of a suitable sodium silicate is ECONOLITETM additive, available from Halliburton Energy Services, Inc.
- the lightweight additive may be present in an amount in the range of from about 0.1 % to about 20% bwocc, for example. In alternative embodiments, the lightweight additive may be present in an amount in the range of from about 1% to about 10% bwocc.
- embodiments of the treatment fluids may be foamed with a gas, for example, to provide a treatment fluid with a reduced density. It should be understood that reduced densities may be needed in displacement embodiments to more approximately match the density of a particular drilling fluid, for example, where lightweight drilling fluids are being used.
- the drilling fluid 126 may be considered lightweight if it has a density of less than about 13 ppg, alternatively, less than about 10 ppg, and alternatively less than about 9 ppg.
- the treatment fluids may be foamed to have a density within about 10% of the density of the drilling fluid 126 and, alternatively, within about 5% of the density of the drilling fluid 126.
- While techniques such as lightweight additives, may be used to reduce the density of the treatment fluids comprising kiln dust without foaming, these techniques may have drawbacks. For example, reduction of the treatment fluid's density to below about 13 ppg using lightweight additives may produce unstable slurries, which can have problems with settling of solids, floating of lightweight additives, and free water, among others. Accordingly, the treatment fluid may be foamed to provide a treatment fluid having a reduced density that is more stable.
- the treatment fluids may be foamed and comprise water, kiln dust, a foaming agent, and a gas.
- the treatment fluid may further comprise a lightweight additive, for example.
- a base slurry may be prepared that may then be foamed to provide an even lower density.
- the foamed treatment fluid may have a density in the range of from about 4 ppg to about 13 ppg and, alternatively, about 7 ppg to about 9 ppg.
- a base slurry may be foamed from a density of in the range of from about 9 ppg to about 13 ppg to a lower density, for example, in a range of from about 7 ppg to about 9 ppg.
- the gas used in embodiments of the foamed treatment fluids may be any suitable gas for foaming the treatment fluid, including, but not limited to air, nitrogen, and combinations thereof.
- the gas should be present in embodiments of the foamed treatment fluids in an amount sufficient to form the desired foam.
- the gas may be present in an amount in the range of from about 5% to about 80% by volume of the foamed treatment fluid at atmospheric pressure, alternatively, about 5% to about 55% by volume, and, alternatively, about 15% to about 30% by volume.
- embodiments of the treatment fluids may comprise a foaming agent for providing a suitable foam.
- foaming agent refers to a material (e.g., surfactant) or combination of materials that facilitate the formation of a foam in a liquid, for example, by reduction of surface tension. Any suitable foaming agent for forming a foam in an aqueous liquid may be used in embodiments of the treatment fluids.
- suitable foaming agents may include, but are not limited to: mixtures of an ammonium salt of an alkyl ether sulfate, a cocoamidopropyl betaine surfactant, a cocoamidopropyl dimethylamine oxide surfactant, sodium chloride, and water; mixtures of an ammonium salt of an alkyl ether sulfate surfactant, a cocoamidopropyl hydroxysultaine surfactant, a cocoamidopropyl dimethylamine oxide surfactant, sodium chloride, and water; hydrolyzed keratin; mixtures of an ethoxylated alcohol ether sulfate surfactant, an alkyl or alkene amidopropyl betaine surfactant, and an alkyl or alkene dimethylamine oxide surfactant; aqueous solutions of an alpha-olefinic sulfonate surfactant and a betaine surfactant; and combinations thereof.
- foaming agent is FOAMERTM 760 foamer/stabilizer, available from Halliburton Energy Services, Inc.
- the foaming agent may be present in embodiments of the foamed treatment fluids in an amount sufficient to provide a suitable foam. In some embodiments, the foaming agent may be present in an amount in the range of from about 0.8% to about 5% by volume of the water ("bvow").
- additives may be included in the treatment fluids as deemed appropriate by one skilled in the art, with the benefit of this disclosure.
- additives include, but are not limited to: supplementary cementitious materials, weighting agents, viscosifying agents (e.g., clays, hydratable polymers, guar gum), fluid loss control additives, lost circulation materials, filtration control additives, dispersants, defoamers, corrosion inhibitors, scale inhibitors, formation conditioning agents, and water-wetting surfactant.
- Water-wetting surfactants may be used to aid in removal of oil from surfaces in the wellbore (e.g., the casing) to enhance cement and consolidating spacer fluid bonding.
- suitable weighting agents include, for example, materials having a specific gravity of 3 or greater, such as barite.
- suitable weighting agents include, for example, materials having a specific gravity of 3 or greater, such as barite.
- additives include: organic polymers, biopolymers, latex, ground rubber, surfactants, crystalline silica, amorphous silica, silica flour, fumed silica, nano-clays (e.g., clays having at least one dimension less than 100 nm), salts, fibers, hydratable clays, microspheres, rice husk ash, micro-fine cement (e.g., cement having an average particle size of from about 5 microns to about 10 microns), metakaolin, zeolite, shale, Portland cement, Portland cement interground with pumice, perlite, barite, slag, lime (e.g., hydrated lime), gypsum, and any combinations thereof, and the like.
- a supplementary cementitious material may be included in the treatment fluid in addition to or in place of all or a portion of the kiln dust.
- suitable supplementary cementitious materials include, without limitation, Portland cement, Portland cement interground with pumice, micro-fine cement, fly ash, slag, pumicite, gypsum and any combination thereof.
- a person having ordinary skill in the art, with the benefit of this disclosure, will readily be able to determine the type and amount of additive useful for a particular application and desired result. It should be understood that, while the present disclosure describes a number of optional additives that may be included in the treatment fluids, it is intended to cover all combinations of the disclosed additives.
- embodiments of the treatment fluids may be consolidating in that the treatment fluids may develop gel strength and/or compressive strength in the wellbore 1 18.
- Consolidation is defined herein as one of three types of material behavior: Type 1 consolidation is identifiable as a gelled fluid that can be moved and/or pumped when the hydraulic shear stress exceeds the yield point (YP) of the gel. Type 2 consolidation is identifiable as a plastic semi-solid that can experience "plastic deformation” if the shear stress, compressive stress, or tensile stress exceeds the "plastic yield limit.”
- Type 3 consolidation is identifiable as a rigid solid similar to regular set cement.
- Type 3 consolidated material During a steady progressive strain rate during conventional compressive testing, both confined and unconfined, a Type 3 consolidated material would exhibit linear elastic Hookean stress-strain behavior, followed by some plastic yield and/or mechanical failure.
- the treatment fluid may transform from the pumpable fluid that was placed during the normal displacement operation to Type 1 and/or further progress to Type 2 and/or further progress to Type 3.
- wellbore conditions may vary.
- embodiments of the treatment fluids may be characterized by exhibiting Type 1 , Type 2, or Type 3 consolidation under specific wellbore conditions.
- Specific examples of how to characterize a Type 1 consolidation include measuring the yield stress.
- Type 1 consolidation exhibits a YP from about 25 Pascals to about 250 Pascals, where YP is measured by one of the methods described in U.S. Patent No. 6,874,353, namely: using a series of parallel vertical blades on a rotor shaft, referred to by those skilled in the art as the "Vane Method"; or using the new device and method also described in U.S. Patent No. 6,874,353.
- Another method used to define the YP of Type 1 consolidation is defined in Morgan, R.G., Suter, D.A., and Sweat, V.A., Mathematical Analysis of a Simple Back Extrusion Rheometer, ASAE Paper No. 79-6001.
- Type 1 consolidation may exhibit SGS values from about 70 lbf/100 ft 2 up to about 500 lbf/100 ft 2 .
- YL-C refers to the yield limit in compression
- Permanent deformation refers to a measurable deformation strain that does not return to zero over a period of time that is on the same order of magnitude as the total time required to conduct the measurement.
- YL- C may range from 1 psi (lbf/in 2 ) to 2,000 psi, with the most common values ranging from 5 psi to 500 psi.
- Type 3 consolidation will exhibit unconfined uniaxial compressive strengths ranging from about 5 psi to about 10,000 psi, while the most common values will range from about 10 psi to about 2,500 psi. These values are achieved in 7 days or less. Some formulations may be designed so as to provide significant compressive strengths within 24 hours to 48 hours. Typical sample geometry and sizes for measurement are similar to, but not limited to, those used for characterizing oil well cements: 2 inch cubes; or 2 inch diameter cylinders that are 4 inches in length; or 1 inch diameter cylinders that are 2 inches in length; and other methods known to those skilled in the art of measuring "mechanical properties" of oil well cements.
- the compressive strength may be determined 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).
- Compressive strengths may be determined in accordance with API RP 10B-2, Recommended Practice for Testing Well Cements, First Edition, July 2005.
- the treatment fluid when left in an annulus 130 (e.g., between walls of the wellbore 1 18 and the casing 108 or between the casing 108 and a larger conduit disposed in the wellbore 1 18), the treatment fluid may consolidate to develop static gel strength and/or compressive strength.
- the consolidated mass formed in the annulus 130 may act to support and position the casing 108 in the wellbore 1 18 and bond the exterior surface of the casing 108 to the walls of the wellbore 1 18 or to the larger conduit.
- the consolidated mass formed in the annulus 130 may also provide a substantially impermeable barrier to seal off formation fluids and gases and consequently also serve to mitigate potential fluid migration.
- the consolidated mass formed in the annulus 130 may also protect the casing 108 or other conduit from corrosion.
- consolidation of the treatment fluid (e.g., spacer fluid 140 or cement composition 142) in the wellbore 1 18 may be measured.
- the consolidation measurement may also include a measurement of the integrity of the bond formed between the consolidated treatment fluid and the exterior wall of the casing 108 and/or between the consolidated fluid and the walls of the wellbore 1 18 or larger conduit disposed in the wellbore 1 18.
- data may be collected corresponding to the integrity of this bond, and the data may be recorded on a log, commonly referred to as a "bond long.”
- the bond log may be used to, for example, analyze the consolidation properties of the treatment fluid in the wellbore 1 18.
- embodiments may include running a cement bond log on at least the portion of the wellbore 1 18 containing the consolidated treatment fluid.
- the cement bond log for the consolidated treatment fluid may be obtained by any method used to measure cement integrity without limitation.
- a tool may be run into the wellbore 1 18 on a wireline that can detect the bond of the consolidated treatment fluid to the casing 108 and/or the walls of the wellbore 1 18 (or larger conduit).
- An example of a suitable tool includes a sonic tool.
- Embodiments of the treatments fluids may have a transition time that is shorter than the transition time of another fluid (e.g., cement composition 142) subsequently introduced into the wellbore 1 18.
- transition time refers to the time for a fluid to progress from a static gel strength of about 100 lbf/100 ft 2 to about 500 lbf/100 ft 2 .
- the treatment fluid can reduce or even prevent migration of gas in the wellbore 1 18, even if gas migrates through a subsequently introduced cement composition 124 before it has developed sufficient gel strength to prevent such migration.
- Gas and liquid migration can typically be prevented at a static gel strength of 500 lbf/100 ft 2 .
- the subsequently added cement composition 142 can progress through its slower transition period without gas migration being as significant factor as the cement develops static gel strength.
- Some embodiments of the treatment fluids may have a transition time (i.e., the time to progress from a static gel strength of about 100 lbf/100 ft 2 to about 500 lbf/100 ft 2 ) at wellbore conditions of about 45 minutes or less, about 30 minutes or less, about 20 minutes or less, or about 10 minutes or less.
- Embodiments of the treatment fluids also quickly develop static gel strengths of about 100 lbf/100 ft 2 and about 500 lbf/100 ft 2 , respectively, at wellbore conditions.
- the time for a fluid to a develop a static gel strength of about 100 lbf/100 ft 2 is also referred to as the "zero gel time/'
- the treatment fluids may have a zero gel time at wellbore condition of about 8 hours or less, and, alternatively, about 4 hours or less.
- the treatment fluids may have a zero gel time in a range of from about 0 minutes to about 4 hours or longer.
- the treatment fluids may develop static gel strengths of about 500 lbf/100 ft 2 or more at wellbore conditions in a time of from about 10 minutes to about 8 hours or longer.
- the preceding time for development of static gel strengths are listed as being at wellbore conditions.
- wellbore conditions e.g., temperature, pressure, depth, etc.
- Static gel strength may be measured in accordance with API Recommended Practice on Determining the Static Gel Strength of Cement Formations, ANSI/API Recommended Practice 10B-6.
- Embodiments of the treatment fluids may be prepared in accordance with any suitable technique.
- the desired quantity of water may be introduced into a mixer (e.g., a cement blender) followed by the dry blend.
- the dry blend may comprise the kiln dust and additional solid additives, for example. Additional liquid additives, if any, may be added to the water as desired prior to, or after, combination with the dry blend.
- This mixture may be agitated for a sufficient period of time to form a base slurry.
- This base slurry may then be introduced into the wellbore 1 18 via pumps (e.g., cementing unit 144), for example.
- the base slurry may be pumped into the wellbore 1 18, and a foaming agent may be metered into the base slurry followed by injection of a gas, e.g., at a foam mixing "T," in an amount sufficient to foam the base slurry thereby forming a foamed treatment fluid, in accordance with certain embodiments.
- a gas e.g., at a foam mixing "T”
- the foamed treatment fluid may be introduced into the wellbore 1 18.
- other suitable techniques for preparing treatment fluids may be used in accordance with the present disclosure.
- methods may include enhancing rheological properties of a treatment fluid (e.g., spacer fluid 140, cement composition 142, etc.).
- the method may comprise including kiln dust in a treatment fluid.
- Optional additives as described previously may also be included in the treatment fluid.
- the kiln dust may be included in the treatment fluid in an amount sufficient to provide a higher yield point than a first fluid.
- the higher yield point may be desirable, for example, to effectively displace the first fluid from the wellbore.
- yield point refers to the resistance of a fluid to initial flow, or representing the stress required to start fluid movement.
- the yield point of the treatment fluid at a temperature of up to about 180°F is greater than about 5 lb/100 ft 2 . In an embodiment, the yield point of the treatment fluid at a temperature of up to about 180°F is greater than about 10 lb/100 ft 2 . In an embodiment, the yield point of the treatment fluid at a temperature of up to about 180°F is greater than about 20 lb/100 ft 2 . It may be desirable for the treatment fluid to not thermally thin to a yield point below the first fluid at elevated temperatures. Accordingly, the treatment fluid may have a higher yield point than the first fluid at elevated temperatures, such as 180°F or bottom hole static temperature ("BHST").
- BHST bottom hole static temperature
- the treatment fluid may have a yield point that increases at elevated temperatures.
- the treatment fluid may have a yield point that is higher at 180° F than at 80°F.
- the treatment fluid may have a yield point that is higher at BHST than at 80°F.
- the treatment fluids may be used in the displacement of a drilling fluid 126 from a wellbore 1 18.
- the drilling fluid 126 may include, for example, any number of fluids, such as solid suspensions, mixtures, and emulsions.
- the drilling fluid 126 may comprise an oil-based drilling fluid.
- An example of a suitable oil- based drilling fluid comprises an invert emulsion.
- the oil-based drilling fluid may comprise an oleaginous fluid.
- oleaginous fluids examples include, but are not limited to, a-olefins, internal olefins, alkanes, aromatic solvents, cycloalkanes, liquefied petroleum gas, kerosene, diesel oils, crude oils, gas oils, fuel oils, paraffin oils, mineral oils, low-toxicity mineral oils, olefins, esters, amides, synthetic oils (e.g., polyolefins), polydiorganosiloxanes, siloxanes, organosiloxanes, ethers, acetals, dialkylcarbonates, hydrocarbons, and combinations thereof.
- a-olefins examples include, but are not limited to, a-olefins, internal olefins, alkanes, aromatic solvents, cycloalkanes, liquefied petroleum gas, kerosene, diesel oils, crude oils, gas oils, fuel oils, paraffin oils, mineral oils, low-toxicity mineral oils
- Sample treatment fluids were prepared to evaluate the rheological properties of spacer fluids containing kiln dust.
- cement kiln dust was used.
- the sample treatment fluids were prepared as follows. First, all dry components (e.g., cement kiln dust, fly ash, bentonite, free water control additive, etc.) were weighed into a glass container having a clean lid and agitated by hand until blended. Tap water was then weighed into a Waring blender jar. The dry components were then mixed into the water with 4,000 rpm stirring. The blender speed was then increased to 12,000 rpm for about 35 seconds.
- dry components e.g., cement kiln dust, fly ash, bentonite, free water control additive, etc.
- Sample Spacer Fluid No. 1 was an 1 1 pound per gallon slurry that comprised 60.62% water, 34.17% cement kiln dust, 4.63% fly ash, and 0.58% free water control additive (WG-17TM solid additive).
- Sample Spacer Fluid No. 2 was an 1 1 pound per gallon slurry that comprised 60.79% water, 30.42% cement kiln dust, 4.13% fly ash, 0.17% free water control additive (WG-17TM solid additive), 3.45% bentonite, and 1.04% EconoliteTM additive.
- Dial readings were recorded at speeds of 3, 6, 100, 200, and 300 with a B l bob, an Rl rotor, and a 1 .0 spring.
- the dial readings, plastic viscosity, and yield points for the spacer fluids were measured in accordance with API Recommended Practices 10B, Bingham plastic model and are set forth in the table below.
- the abbreviation “PV” refers to plastic viscosity
- the abbreviation “YP” refers to yield point.
- the thickening time of the Sample Fluid No. 1 was also determined in accordance with API Recommended Practice 10B at 205° F. Sample Fluid No. 1 had a thickening time of more than 6:00+ hours.
- the above example illustrates that the addition of cement kiln dust to a treatment fluid may provide suitable properties for use in subterranean applications.
- the above example illustrates, inter alia, that the cement kiln dust may be used to provide a treatment fluid that may not exhibit thermal thinning with the treatment fluid potentially even having a yield point that increases with temperature.
- Sample Fluid No. 2 had a higher yield point at 180° F than at 80° F.
- the yield point of Sample Fluid No. 1 had only a slight decrease at 180° F as compared to 80° F.
- addition of the cement kiln dust to a treatment fluid may provide a plastic viscosity that increases with temperature.
- sample treatment fluids were prepared to further evaluate the rheological properties of spacer fluids containing kiln dust.
- Cement kiln dust was used in this example, The sample treatment fluids were prepared as follows. First, all dry components (e.g., cement kiln dust, fly ash) were weighed into a glass container having a clean lid and agitated by hand until blended. Tap water was then weighed into a Waring blender jar. The dry components were then mixed into the water with 4,000 rpm stirring. The blender speed was then increased to 12,000 rpm for about 35 seconds.
- dry components e.g., cement kiln dust, fly ash
- Sample Fluid No. 3 was a 12.5 pound per gallon fluid that comprised 47.29% water and 52.71 % cement kiln dust.
- Sample Fluid No. 4 was a 12.5 pound per gallon fluid that comprised 46.47% water, 40.15% cement kiln dust, and 13.38% fly ash.
- Sample Fluid No. 5 was a 12.5 pound per gallon fluid that comprised 45.62% water, 27.19% cement kiln dust, and 27.19% fly ash.
- Sample Fluid No. 6 was a 12.5 pound per gallon fluid that comprised 44.75% water, 13.81% cement kiln dust, and 41.44% fly ash.
- Sample Fluid No. 7 (comparative) was a 12.5 pound per gallon fluid that comprised 43.85% water, and 56.15% fly ash.
- Dust- 600 300 200 100 60 30 6 3
- the above example illustrates that the addition of the cement kiln dust to a treatment fluid may provide suitable properties for use in subterranean applications.
- the above example illustrates, inter alia, that the cement kiln dust may be used to provide a treatment fluid that may not exhibit thermal thinning with the treatment fluid potentially even having a yield point that increases with temperature.
- higher yield points were observed for treatment fluids with higher concentrations of the cement kiln dust.
- a sample treatment fluid containing kiln dust was prepared to compare the rheological properties of a treatment fluid containing kiln dust with an oil-based drilling fluid.
- cement kiln dust was used.
- the sample fluid was prepared as follows. First, all dry components (e.g., cement kiln dust, fly ash, bentonite, etc.) were weighed into a glass container having a clean lid and agitated by hand until blended. Tap water was then weighed into a Waring blender jar. The dry components were then mixed into the water with 4,000 rpm stirring. The blender speed was then increased to 12,000 rpm for about 35 seconds.
- dry components e.g., cement kiln dust, fly ash, bentonite, etc.
- Sample Fluid No. 8 was an 1 1 pound per gallon slurry that comprised 60.79% water, 30.42% cement kiln dust, 4.13% fly ash, 0.17% free water control additive (WG- 17TM solid additive), 3.45% bentonite, and 1.04% EconoliteTM additive.
- the oil-based drilling fluid was a 9.1 pound per gallon oil-based mud.
- the above example illustrates that the addition of cement kiln dust to a treatment fluid may provide suitable properties for use in subterranean applications.
- the above example illustrates, inter alia, that the cement kiln dust may be used to provide a treatment fluid with a yield point that is greater than a drilling fluid even at elevated temperatures.
- Sample Fluid No. 8 has a higher yield point at 180° F than the oil- based mud.
- a foamed treatment fluid (Sample Fluid 9) was prepared that comprised cement kiln dust.
- a base slurry was prepared that had a density of 10 ppg and comprised cement kiln dust, a free water control additive (0.7% by weight of cement kiln dust), a lightweight additive (4% by weight of cement kiln dust), and fresh water (32.16 gallons per 94-pound sack of cement kiln dust).
- the free water control additive was SA- 1015TM suspending aid.
- the lightweight additive was ECONOLITETM additive.
- a foaming agent (FOA ERTM 760 foamer/stabilizer) in an amount of 2% bvow was added, and the base slurry was then mixed in a foam blending jar for 4 seconds at 12,000 rpm.
- the resulting foamed treatment fluid had a density of 8.4 ppg.
- the "sink" of the resultant foamed treatment fluid was then measured using a free fluid test procedure as specified in API Recommended Practice 10B. However, rather than measuring the free fluid, the amount of "sink” was measured after the foamed treatment fluid remained static for a period of 2 hours.
- the foamed treatment fluid was initially at 200° and cooled to ambient temperature over the 2-hour period.
- the measured sink for this foamed treatment fluid was 5 millimeters.
- Example Fluid 10 Another foamed treatment fluid (Sample Fluid 10) was prepared that comprised cement kiln dust.
- a base slurry was prepared that had a density of 10.5 ppg and comprised cement kiln dust, a free water control additive (0.6% by weight of cement kiln dust), a lightweight additive (4% by weight of cement kiln dust), and fresh water (23.7 gallons per 94-pound sack of cement kiln dust).
- the free water control additive was SA- 1015TM suspending aid.
- the lightweight additive was ECONOLITETM additive.
- a foaming agent (a hexylene glycol/cocobetaine blended surfactant) in an amount of 2% bvow was added, and the base slurry was then mixed in a foam blending jar for 6 seconds at 12,000 rpm.
- the resulting foamed treatment fluid had a density of 8.304 ppg.
- the resultant foamed treatment fluid had a sink of 0 millimeters, measured as described above for Example 4.
- sample fluids 1 1 -32 in the table below were prepared having a density of 12.5 ppg using various concentrations of additives. The amount of these additives in each sample fluid are indicated in the table below with "% by weight” indicating the amount of the particular component by weight of Additive 1 + Additive 2.
- the abbreviation "gal/sk” in the table below indicates gallons of the particular component per 94-pound sack of Additive 1 and Additive 2.
- the shale used was supplied by Texas Industries, Inc., from Midlothian, Texas.
- the pumice used was either DS-200 or DS-300 lightweight aggregate available from Hess Pumice Products, Inc.
- the silica flour used was SSA-1TM cement additive, from Halliburton Energy Services, Inc.
- the course silica flour used was SSA-2TM course silica flour, from Halliburton Energy Services, Inc.
- the metakaolin used was MetaMax ® metakaolin, from BASF.
- the amorphous silica used was SILICALITETM cement additive, from Halliburton Energy Services, Inc.
- the perlite used was supplied by Hess Pumice Products, Inc.
- the slag used was supplied by LaFarge North America.
- the Portland cement Interground with pumice was FineCemTM cement, from Halliburton Energy Services, Inc.
- the fly ash used was POZMIX ® cement additive, from Halliburton Energy Services, Inc.
- the micro-fine cement used was MICRO MATRIX ® cement having an average particle size of 7.5 microns, from Halliburton Energy Services, Inc.
- the rice husk ash used was supplied by Rice Hull Specialty Products, Stuttgart, Arkansas.
- the biopolymer used was supplied by CP Kelco, San Diego, California.
- the barite used was supplied by Baroid Industrial Drilling Products.
- the latex used was Latex 3000TM cement additive from Halliburton Energy Services, Inc.
- the ground rubber used was LIFECEMTM 100 cement additive from Halliburton Energy Services, Inc.
- the nano-clay used was supplied by Nanocor Inc.
- the set retarder used was SCR-100TM cement retarder, from Halliburton Energy Services, Inc.
- SCR-100TM cement retarder is a copolymer of acrylic acid and 2-acrylamido-2-methylpropane sulfonic acid.
- a treatment fluid comprising kiln dust may be capable of consolidation.
- 7-day compressive strengths of 1000 psi or even higher were observed for certain sample slurries.
- EXAMPLE 7 The following series of tests were performed to evaluate the thickening times of sample treatment fluids. For this example, the thickening times for Sample Fluids 1 1 -32 from Example 6 were determined. As indicated below, the compositions for Samples Fluids 1 1 -32 were the same as from Example 6 except the concentration of the cement set retarder was adjusted for certain samples. The thickening time, which is the time required for the compositions to reach 70 Bearden units of consistency, was determined for each fluid at 230°F in accordance with API RP 10B-2. The results of these tests are set forth below. The term “cement kiln dust" is abbreviated "CKD" in the table below.
- cement kiln dust cement kiln dust
- a settable spacer fluid may have acceptable thickening times for certain applications.
- Sample Fluids 1 1 - 32 were determined. The rheological values were determined using a Fann Model 35 Viscometer. Dial readings were recorded at speeds of 3, 6, 30, 60, 100, 200, 300, and 600 with a B l bob, an Rl rotor, and a 1.0 spring. An additional sample was used for this specific test. It is Sample Fluid 33 and comprised barite and 0.5% of a suspending agent by weight of the barite. The suspending agent was SATM-1015, available from Halliburton Energy Services, Inc. The water was included in an amount sufficient to provide a density of 12.5 ppg. Sample 33's rheological properties were measured twice at two different temperatures and the values per temperature were averaged to present the data shown below. Temperature is measured in degrees Fahrenheit. The results of these tests are set forth below.
- a treatment fluid may have acceptable rheological properties for a particular application.
- the cement kiln dust used was Mountain cement kiln dust from Laramie Wyoming, except for Sample Fluid 43 which used cement kiln dust from Holcim (US) Inc., Ada, Oklahoma.
- the Portland cement used in Sample Fluids 34 and 35 was CEMEX Type 3 Portland cement, from CEMEX USA.
- the cement accelerator used in Sample Fluid 34 was CAL-SEALTM accelerator, from Halliburton Energy Services Inc. CAL-SEALTM Accelerator is gypsum.
- the Class F fly ash used in Slurries 37-41 was from Coal Creek Station.
- the Class C fly ash used in Slurries 36 was from LaFarge North America.
- a treatment fluid may have acceptable compressive strengths for certain applications.
- the sample comprised a blend of cement kiln dust (80% by weight), fly ash (16% by weight) and hydrated lime (4% by weight).
- the sample also comprised a suspending aid in an amount of 0.4% by weight of the blend. Sufficient water was included in the sample to provide a density of 11 ppg.
- the cement kiln dust used was from Holcim (US) Inc., Ada, Oklahoma.
- the fly ash used was POZMIX ® cement additive, from Halliburton Energy Services, Inc.
- the suspending agent was SA TM -1015 suspending agent, available from Halliburton Energy Services, Inc.
- Sample Fluid 45 the sample comprised a mixture of cement kiln dust (80% by weight), fly ash (16% by weight), and hydrate lime (4% by weight). Sufficient water was included in the sample to provide a density of 13.5 ppg.
- the cement kiln dust used was from Holcim (US) Inc., Ada, Oklahoma.
- the fly ash used was POZM1X ® cement additive, from Halliburton Energy Services, Inc.
- FIGS. 1 and 2 show the static gel strength measurements for Sample Fluids 44 and 45, respectively, as a function of time. As seen in the figures, the samples progress through the transition time, defined as the time between 100 SGS and 500 SGS, very quickly with a total transition time of 19 minutes for the sample 34 and 6 minutes for sample 35. These short transition times are faster than most cement compositions.
- Samples Fluids 46 and 47 were prepared having a density of 13.002 and 10.999 ppg respectively using various concentrations of additives.
- the component concentrations of each sample are as follows:
- the sample comprised a blend of cement kiln dust (100% by weight), POZMIX ® cement additive (50% by weight of the cement kiln dust), HR ® -601 cement retarder (1 % by weight of the cement kiln dust), HR ® -25 cement retarder (0.6% by weight of the cement kiln dust), and D-Air 5000TM defoamer (0.5% by weight of the cement kiln dust).
- Sufficient water was included in the sample to provide a density of 13.002 ppg.
- the cement kiln dust used was from Holcim (US) Inc., Ada, Oklahoma.
- POZMIX ® cement additive was from Halliburton Energy Services, Inc.
- HR ® -601 cement retarder was from Halliburton Energy Services, Inc.
- HR ® -25 cement retarder was from Halliburton Energy Services, Inc.
- D-Air 5000 TM defoamer was from Halliburton Energy Services, Inc.
- the sample comprised a blend of cement kiln dust (100% by weight), SA-1015 (0.4% by weight of the cement kiln dust), and D-Air 5000 TM defoamer (0.5% by weight of the cement kiln dust). Sufficient water was included in the sample to provide a density of 10.999 ppg.
- the cement kiln dust used was from Holcim (US) Inc., Ada, Oklahoma.
- SA TM - 1015 suspending agent was from Halliburton Energy Services, Inc.
- D-Air 5000TM defoamer was from Halliburton Energy Services, Inc.
- Sample Fluid 47 progresses through the transition time, defined as the time between 100 SGS and 500 SGS, very quickly with a total transition time of 10 minutes. Sample Fluid 46 is much slower taking over an hour to progress through the transition time. The short transition time of Sample Fluid 47 is faster than most cement compositions.
- 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 (6)
Application Number | Priority Date | Filing Date | Title |
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CA2926226A CA2926226C (en) | 2013-11-26 | 2014-11-21 | Placing a fluid comprising kiln dust in a wellbore through a bottom hole assembly |
AU2014354985A AU2014354985B2 (en) | 2013-11-26 | 2014-11-21 | Placing a fluid comprising kiln dust in a wellbore through a bottom hole assembly |
GB1605237.5A GB2537236B (en) | 2013-11-26 | 2014-11-21 | Placing a fluid comprising kiln dust in a wellbore through a bottom hole assembly |
RU2016116019A RU2657276C1 (en) | 2013-11-26 | 2014-11-21 | Placing a fluid comprising kiln dust in a wellbore through a bottom hole assembly |
MX2016005289A MX2016005289A (en) | 2013-11-26 | 2014-11-21 | Placing a fluid comprising kiln dust in a wellbore through a bottom hole assembly. |
NO20160668A NO20160668A1 (en) | 2013-11-26 | 2016-04-21 | Placing a fluid comprising kiln dust in a wellbore through a bottom hole assembly |
Applications Claiming Priority (2)
Application Number | Priority Date | Filing Date | Title |
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US14/091,332 US9051505B2 (en) | 2005-09-09 | 2013-11-26 | Placing a fluid comprising kiln dust in a wellbore through a bottom hole assembly |
US14/091,332 | 2013-11-26 |
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WO2015080977A1 true WO2015080977A1 (en) | 2015-06-04 |
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PCT/US2014/066908 WO2015080977A1 (en) | 2013-11-26 | 2014-11-21 | Placing a fluid comprising kiln dust in a wellbore through a bottom hole assembly |
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AR (2) | AR098479A1 (en) |
AU (1) | AU2014354985B2 (en) |
CA (1) | CA2926226C (en) |
GB (1) | GB2537236B (en) |
MX (1) | MX2016005289A (en) |
NO (1) | NO20160668A1 (en) |
RU (1) | RU2657276C1 (en) |
WO (1) | WO2015080977A1 (en) |
Cited By (1)
Publication number | Priority date | Publication date | Assignee | Title |
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CN113355067A (en) * | 2021-06-07 | 2021-09-07 | 湖南省城乡建设勘测院 | High-performance drilling fluid suitable for solid sylvite ore layer and preparation method thereof |
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US7204310B1 (en) * | 2006-04-11 | 2007-04-17 | Halliburton Energy Services, Inc. | Methods of use settable drilling fluids comprising cement kiln dust |
WO2009029800A1 (en) * | 2007-08-30 | 2009-03-05 | Baker Hughes Incorporated | Apparatus and method for drilling wellbores that utilize a detachable reamer |
US20100294496A1 (en) * | 2009-05-22 | 2010-11-25 | Lafarge | Low density cementitious compositions |
US20120193097A1 (en) * | 2005-09-09 | 2012-08-02 | Halliburton Energy Services, Inc. | Methods and Compositions Comprising Kiln Dust and Metakaolin |
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GB2414502B (en) * | 2003-02-27 | 2007-10-17 | Weatherford Lamb | Drill shoe |
FI121025B (en) * | 2004-12-07 | 2010-06-15 | Sandvik Mining & Constr Oy | Method for pipe drilling, drilling unit and adapter device |
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2014
- 2014-11-19 AR ARP140104354A patent/AR098479A1/en active IP Right Grant
- 2014-11-21 RU RU2016116019A patent/RU2657276C1/en active
- 2014-11-21 CA CA2926226A patent/CA2926226C/en not_active Expired - Fee Related
- 2014-11-21 MX MX2016005289A patent/MX2016005289A/en unknown
- 2014-11-21 WO PCT/US2014/066908 patent/WO2015080977A1/en active Application Filing
- 2014-11-21 AU AU2014354985A patent/AU2014354985B2/en active Active
- 2014-11-21 GB GB1605237.5A patent/GB2537236B/en active Active
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2016
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Patent Citations (4)
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US20120193097A1 (en) * | 2005-09-09 | 2012-08-02 | Halliburton Energy Services, Inc. | Methods and Compositions Comprising Kiln Dust and Metakaolin |
US7204310B1 (en) * | 2006-04-11 | 2007-04-17 | Halliburton Energy Services, Inc. | Methods of use settable drilling fluids comprising cement kiln dust |
WO2009029800A1 (en) * | 2007-08-30 | 2009-03-05 | Baker Hughes Incorporated | Apparatus and method for drilling wellbores that utilize a detachable reamer |
US20100294496A1 (en) * | 2009-05-22 | 2010-11-25 | Lafarge | Low density cementitious compositions |
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Cited By (2)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
CN113355067A (en) * | 2021-06-07 | 2021-09-07 | 湖南省城乡建设勘测院 | High-performance drilling fluid suitable for solid sylvite ore layer and preparation method thereof |
CN113355067B (en) * | 2021-06-07 | 2022-08-05 | 湖南省城乡建设勘测院 | High-performance drilling fluid suitable for solid sylvite ore layer and preparation method thereof |
Also Published As
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GB2537236A (en) | 2016-10-12 |
NO20160668A1 (en) | 2016-04-21 |
CA2926226C (en) | 2019-06-11 |
MX2016005289A (en) | 2016-07-12 |
AU2014354985B2 (en) | 2017-02-16 |
CA2926226A1 (en) | 2015-06-04 |
RU2657276C1 (en) | 2018-06-09 |
RU2016116019A (en) | 2018-01-09 |
AR098479A1 (en) | 2016-06-01 |
AU2014354985A1 (en) | 2016-04-21 |
GB2537236B (en) | 2018-01-03 |
GB201605237D0 (en) | 2016-05-11 |
AR115902A2 (en) | 2021-03-10 |
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