Placing a fluid comprising kiln dust in a wellbore through a bottom hole assembly

PLACEMENT OF A FLUID COMPRISING FURNACE DUST INTO A WELL THROUGH A BOTTOM WELL ASSEMBLY

CROSS REFERENCE TO RELATED REQUESTS

The present application is a continuation in part of United States Patent Application No. 13/851,925, filed March 27, 2013, which is a divisional application of United States Patent Application No. 13/725,833, filed on December 21, 2012, granted as United States Patent No. 8,505,630 on August 13, 2013, which is a continuation in part of United States Application No. 13/535,145, filed June 27, 2012, granted as US Patent No. 8,505,629 on August 13, 2013, which is a continuation in part of US Application No. 12/895,436, filed on 30 September 2010, granted as United States Patent No. 8,522,872 on September 3, 2013, which is a continuation in part of United States Application No. 12/264,010, filed on November 3, 2008, granted as United States Patent No. 8,333,240 on December 18, 2012, which is a continuation in part of US Application No. 11/223,669, filed on September 9, 2005, granted as US Patent No. 7,445,669 on November 4 2008, the specification of which is incorporated herein by reference in its entirety.

BACKGROUND

File *"^ace f°^rmas of realization are related to underground operations and,

233,986 in some embodiments, with the introduction of fluids comprising furnace dust into a well through a downhole assembly.

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Page 1 of 54

Wells are usually drilled into the ground to recover natural deposits of hydrocarbons or other useful materials trapped in geological formations in the Earth's crust. Wells can be drilled by rotating a drill bit that is located in a downhole assembly at the distal end of a drill string. In conventional drilling, a well is drilled to a stipulated depth and then the well is lined with a larger diameter pipe, usually referred to as casing. Before the casing is inserted and cemented in place, the drill string and drill bit are removed from the well. Once the casing is cemented in place, drilling continues. In some cases, a technique called 'casing drilling' is used in which casing is used instead of a drill string. As with 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. Once the well is drilled to a target depth, the casing can be cemented in place. In some cases, the cement compositions and associated spacer fluids used in the cementing operation are placed in the wellbore through the downhole assembly. Casing drilling allows drilling and casing of the well without the delays associated with removing the drill bit and drill string from the well.

A number of different fluids can be used in drilling and casing the well. For example, a drilling fluid can be pumped down the drill string (or casing), out the drilling bit, and returned to the surface in the

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Page 2 of 54 annular space between the drill string and the wellbore wall. The drilling fluid can act to lubricate and cool the drill bit and also carry drill cuttings back to the surface. Spacer fluids can also be used in these operations. For example, a spacer fluid may be used to displace drilling fluids from the well prior to the introduction of another fluid, such as a cement composition. Cement compositions can be used to cement the casing in the wellbore. The composition may be allowed to set in the annular space between the casing and the wellbore wall thereby forming an annular sheath of hardened cement, (e.g., a cement sheath) which must support and maintain the position of the pipe string into the well and attach the outer surface of the pipe string to the walls of the well. While a variety of different fluids have been used with some success in well drilling and casing, improved fluids and techniques are needed for their placement in underground operations.

BRIEF DESCRIPTION OF THE DRAWINGS

These drawings illustrate certain aspects of some embodiments and should not be used to limit or define the invention.

FIG. 1 is a schematic view of an illustrative arrangement that can be used for casing during drilling according to various embodiments.

FIG. 2 is a schematic view of an illustrative arrangement that can be used for casing during directional drilling according to various embodiments.

FIGS. 3 and 4 are schematic views illustrating the expulsion of the drilling fluid with the placement of the spacer fluid and the composition of

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Page 3 of 54 cement through a downhole assembly according to various embodiments.

FIG. 5 is a schematic view illustrating the equipment for placing a cement composition in a well according to various embodiments.

FIG. 6 is a graph illustrating static gel strength values ​​measured at various temperature and pressure readings as a time factor corresponding to an illustrative treatment fluid.

FIG. 7 is a graph illustrating static gel strength values ​​measured at various temperature and pressure readings as a time factor corresponding to an illustrative treatment fluid.

DESCRIPTION OF PREFERRED EMBODIMENTS

The embodiments relate to underground operations and, in some embodiments, to the introduction of a treatment fluid comprising furnace dust into a well through a downhole assembly. In specific embodiments, the downhole assembly may be connected to a tubular instrument such as a drill pipe and/or casing. As an example, the treatment fluid may be used in a casing drilling operation, in which the treatment fluid may be introduced into a well through a downhole assembly that is connected to one end. distal of a casing pipe. In some embodiments, the treatment fluid may be introduced through a drilling bit at the distal end of the downhole assembly. The term “treatment fluid” does not necessarily imply any specific action performed by the fluid or any component thereof. The treatment fluids can be used, for

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Page 4 of 54 example, to drill, complete, produce, work over, or otherwise prepare a well and/or well equipment for the recovery of materials residing in an underground formation penetrated by the well.

Referring now to FIG. 1, a casing drilling arrangement 100 is illustrated in accordance with various embodiments. As illustrated, the casing drilling arrangement 100 may include a drilling rig 102 supporting a derrick 104 consisting of a traveling block 106 for raising and lowering a casing 108. The casing 108 may be generally tubular and comprise a string of tubular elements and may include a conductive casing, a surface casing, an intermediate casing, a production casing, or a short casing of production. Casing collars or other suitable connectors may be used to couple the tube joints to form casing 108. In some embodiments, completion equipment may be connected to casing 108. In FIG. 1 components are not shown 1 the individual components of casing 108 In the casing drilling operation, the casing 108 is a pipe generally of larger diameter than that generally used for drilling. A kelly or square stem 110 may support the casing 108 while it is lowered through a rotary table 112. There may be a downhole assembly 114 coupled to the distal end of the casing 108. The downhole assembly 114 may be a retrievable or non-retrievable downhole assembly. The downhole assembly 114 may include a drilling bit 116 at its distal end and may be propelled by a downhole motor and/or by rotation of the drill bit.

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Page 5 of 54 casing 108 from the surface of the well. By rotating the drill bit 116, it generates a hole 118 that penetrates various underground formations 120. In the illustrated embodiment, the downhole assembly 114 further includes a under reamer 122, which can be used to enlarge the hole 118. beyond the diameter of drill bit 116, for example. In some embodiments, the underreamer 122 may be incorporated into the drill bit 116, incorporated into a lower end of the casing 108, or may be a separate component fitted to the drill bit 116. It should be noted that although FIG. 1 generally illustrates a casing drilling arrangement 100 that is land-based, those skilled in the art will readily recognize that the principles described herein apply equally to subsea drilling operations employing floating or offshore platforms and equipment, however deviate from the reach of revelation.

A pump 124 (e.g., a mud pump) may circulate drilling fluid 126 through a feed pipe 128 and into the kelly 110, which transports drilling fluid 126 to the bottom of the well through the interior. of the casing 108 and through one or more holes drilled in the drill bit 116. The drilling fluid 126 may then be circulated back to the surface through an annular space 130 defined between the casing 108 and the borehole walls 118. At the surface, the recirculated or depleted fluid 126 exits the annular space 130 and may be transported to one or more fluid processing units 132 via an interconnected flow line 134. After passing through the fluid processing unit(s) 132, a "clean" drilling fluid 126 may be deposited in a nearby holding pool 136 (e.g., a mud pool). Although it is illustrated ready at the exit of the

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Page 6 of 54 wellbore 118 through the annulus 130, it will be readily appreciated by those skilled in the art that the fluid processing unit (or units) 132 may be arranged elsewhere in the tubing drilling arrangement. of coating 100 to facilitate its correct operation, without departing from the scope of the disclosure.

Referring now to FIG. 2, embodiments may include directional drilling with casing. Directional drilling generally refers to the intentional deviation of the wellbore 118. Directional drilling may allow horizontal drilling through one or more underground formations 120. As illustrated in FIG. 2, directional casing drilling may be used to create a well 118 consisting of a vertical upper section 136 and an inclined lower section 138. Any suitable technique may be employed for creating the inclined lower section 138 that does not It is vertical. In some embodiments, the downhole assembly 114 used in directional casing drilling may be a steerable rotary arrangement that allows directional control during rotation.

Referring now to FIG. 3, drilling fluid 126 may be expelled from wellbore 118 by spacer fluid 140 according to certain embodiments. In some embodiments, the spacer fluid 140 may be a treatment fluid comprising furnace dust and water. The spacer fluid 140 may also expel solids from the drilling fluid, dehydrated/gelled and/or gelled drilling fluid and/or from the wellbore filter cake 118 prior to the cement composition 142. Embodiments of the spacer fluid 140 can improve the removal efficiency of these and other compositions from well 118. Removal of these compositions from well 118 can improve the binding of the composition of

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Page? of 54 cement 142 to the wellbore surfaces 118. In specific embodiments, the spacer fluid 140 may be characterized as having a higher yield point than the drilling fluid 126 at 80°F (26.6°C). In other embodiments, the spacer fluid 140 comprising furnace dust and water may be characterized as having a higher yield point than the drilling fluid 126 at 130°F (52.2 to 54.4°C). In still other embodiments, the spacer fluid 140 comprising kiln powder and water may be characterized as having a higher yield point than the drilling fluid 126 at 180°F (82.2°C).

Spacer fluid 140 may be pumped down through casing 108 and out through downhole assembly 114 and into annulus 130. In some embodiments, spacer fluid 140 may be introduced. into the annulus 130 through the drill bit 116 onto the downhole assembly 114. As illustrated, the spacer fluid 140 can also separate the drilling fluid 126 from a cement composition 142. The cement composition 142 can be introduced into the wellbore 118 behind the spacer fluid 140 to cement the casing 108 in the wellbore. 118. The cement composition 142 may also be pumped down through the casing 108 and out through the downhole assembly 114 and into the annulus 130. In some embodiments, the cement composition 142 may be a treatment fluid comprising kiln powder and water. In some embodiments, both the spacer fluid 140 and the cement composition 142 may comprise kiln dust. In alternative embodiments, one of the spacer fluid 140 or the cement composition 142 may comprise kiln powder. In a further embodiment, at least a portion of the spacer fluid 140 containing

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Page 8 of 54 kiln powder used and/or not used in the cement composition 142 that is placed in the well 118 and allowed to set. As described below in more detail, the spacer fluid 140 and/or the cement composition 142 comprising kiln dust may further comprise one or more additional additives in various concentrations and combinations.

Referring now to FIG. 4, the well 118 is illustrated after the expulsion of the drilling fluid 126 according to various embodiments. As illustrated, the spacer fluid 140 and the cement composition 142 can be arranged in the annulus 130 between the casing 108 and the walls of the wellbore 118. The cement composition 142 can be allowed to consolidate in the annulus 130. More specifically, the cement composition can be allowed to set in the annular space 130 to form an annular sheath of hardened cement. The annular sheath may form a barrier that prevents migration of fluids in the wellbore 118. The annular sheath may also, for example, support the casing 108 in the wellbore 118. In some embodiments, at least a portion of the Spacer fluid 142 may also remain in the annular space 130. The remaining portion of the spacer fluid 142 may consolidate in the annular space 130. For example, the spacer fluid may set and harden to acquire compressive strength through the reaction of the furnace powder in water. The spacer fluid 142 after consolidation can prevent fluid migration in the wellbore 118 and also support the casing 108 in the wellbore 118.

Referring now to FIG. 5, a cementing unit 144 is illustrated that can be used in placing the cement composition 142 in the well 118 according to certain embodiments. Although not illustrated, cementing unit 144 may also be used in placing spacer fluid 140 in well 118. As should be apparent to persons with

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Page 9 of 54 normal training in the art, the cementing unit 144 may include mixing equipment, such as jet mixers, recirculating mixers, or batch mixers. In some embodiments, a jet mixer may be employed, for example, to continuously mix the components of the spacer fluid 140 and/or the cement composition 142 as it is pumped into the well 118. In some embodiments, the cementing unit 144 may include one or more cement changers, including mixing and pumping equipment. As illustrated, the cementing unit 144 may pump the cement composition 142 through a feed pipe. 146 and towards a cementing head 148 that transfers the cement composition 142 into the well 118. As also illustrated, fluids (e.g., spacer fluid 140) returned to the surface in annulus 130 may be deposited, for example, in spade retention basin 150 through flow line 134.

The illustrative treatment fluids described herein may affect, directly or indirectly, one or more components or pieces of equipment associated with the preparation, application, recapture, recycling, reuse and/or disposal of the treatment fluids described. For example, treatment fluids may affect, directly or indirectly, one or more mixers, related mixing equipment, sludge basins (e.g., retention basin 136, spacer retention basin 150), plants, or processing units. storage, composition separators, heat exchangers, sensors, indicators, pumps, compressors and others used to generate, store, monitor, regulate and/or recondition the illustrative treatment fluids. The treatment fluids described here may also affect, directly or indirectly, the transport or application equipment that

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Page 10 of 54 can be used to transport delayed-setting cement compositions to a well site or downhole, such as possible transport vessels, conduits, pipelines, trucks, tubes and/or pipes used to transport compositionally moving treatment fluids from one site to another, any pumps, compressors or motors (e.g., topside or downhole) that may be used to move the treatment fluids, valves or related joints that may be used to regulate the pressure or flow of treatment fluids, sensors (i.e., pressure and temperature), indicators and/or combinations thereof and so on. The treatment fluids described herein may also affect, directly or indirectly, the various downhole equipment and tools that may come into contact with the treatment fluids such as, but not limited to, the well casing. (e.g., 108 casing), well casing, completion string, insert strings, drill string, coiled tubing, recovery wire, support cable, drill pipes, bit collars, mud motors, downhole motors and/or pumps, cement pumps, surface mounted motors and/or pumps, centralizers, turbolyzers, scrapers, floating equipment (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, self-contained inflow control devices, outflow control devices, etc.), couplings (e.g. wet connection electrohydraulic, dry connection, inductive coupler, etc.), control lines (e.g., electrical, fiber optic, hydraulic, etc.), monitoring lines, drilling bits (e.g., drill bit

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Page 11 of 54 drilling 116) and reamers, sensors or distributed sensors, downhole heat exchangers, valves and their corresponding actuation devices, tool closures, plugs, cement plugs, blanking plugs and other devices or components well insulation and so on.

Embodiments of the treatment fluids (e.g., spacer fluid 140, cement composition 142) may comprise kiln dust and water. In some embodiments, the treatment fluids may consolidate by remaining in a well. For example, treatment fluids can set and harden to gain compressive strength through the reaction of kiln powder in water. In some embodiments, the treatment fluids may be foamed. For example, foamed treatment fluids may comprise water, furnace dust, a foaming agent, and a gas. A foamed treatment fluid may be used, for example, when it is desired that the fluid be lightweight and not exert excessive force on the underground formations 120 into which the well 118 penetrates. Embodiments of the treatment fluids may also comprise fly ash, barite, pumicite, a free water control additive, or a combination thereof. According to the present embodiments, the treatment fluid may be a spacer fluid 140 that displaces a first fluid (e.g., a drilling fluid 126) from the well 118. In some embodiments, the spacer fluid 140 may have a higher yield strength than the first fluid. In other embodiments, the treatment fluid may be a cement composition 142 that is used in cementing the casing 108 in the well 118. This embodiment may further comprise the use of a treatment fluid comprising kiln dust in the borehole 118. For example, the kiln dust can be circulated

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Page 12 of 54 treatment fluid beyond the drill bit 116 to carry the drill cuttings back to the surface.

Treatment fluids should generally have a density suitable for a specific application, as deemed appropriate by persons of ordinary skill in the art, with the benefit of this disclosure. In some embodiments, the treatment fluids may have a density in the range of about 4 pounds per gallon (ppg") to about 24 ppg (approximately 479.3 kg/m³ at 2875.8 kg/m³). In other embodiments, the treatment fluids may have a density in the range of about 4 ppg to about 17 ppg (about 479.3 to 2037 kg/m³). In still other embodiments, the treatment fluids may have a density in the range of about 8 ppg to about 13 ppg (958.6 to 1557.7 kg/m³). Embodiments of the treatment fluids may be foamed or non-foamed or comprise other means of reducing their densities known in the art, such as lightweight additives. Persons of ordinary skill in the art, with the benefit of this disclosure, should recognize the appropriate density for a specific application.

Furnace dust refers, in the present context, to a solid material generated as a by-product of heating certain materials in furnaces. In the present context, it is intended that the term 'baking dust'¹ includes kiln powder prepared as described herein and equivalent forms of kiln powder. Kiln dust generally exhibits cementitious properties, since it can set and harden in the presence of water. Examples of suitable kiln dusts include cement kiln dust, lime kiln dust, and combinations thereof. Cement kiln dust can be generated as a by-product of cement production.

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Page 13 of 54 cement that is removed from the gas stream and collected, for example, in a dust collector. Large quantities of cement kiln dust are usually collected in cement production and are usually discarded as waste. Disposal of cement kiln dust can add detrimental costs to cement manufacturing, as well as environmental concerns associated with its disposal. The chemical analysis of cement kiln dust from various cement manufactures varies depending on a number of factors, including the specific kiln feed, the efficiencies of the cement production operation and the associated dust collection arrangements. Cement kiln dust can generally comprise a variety of oxides such as SiO₂₁ A1₂EITHER₃₁ Faith₂EITHER₃, CaO, MgO. SW₃. na₂O and K₂O. There may also be problems associated with the disposal of lime kiln dust, which can be generated as a by-product of lime calcination. The chemical analysis of lime kiln dust from various lime manufactures varies depending on a number of factors, including the specific feed of dolomite limestone, the type of kiln, the mode of operation of the kiln, the efficiencies of the operation of lime production and associated dust collection arrangements. Lime kiln dust may generally comprise varying amounts of free lime and free magnesium, limestone and/or dolomite limestone and a variety of oxides such as SiO.₂, A1₂EITHER₃₁ Faith₂EITHER₃, CaO, MgO, SO₃, Na₂O and K₂O and other components such as chlorides.

Furnace dust may be included in treatment fluid embodiments as a rheology modifier. Among other things, the use of kiln powder in various embodiments can produce treatment fluids with rheology suitable for a specific application. Favorable rheology may be advantageous to produce a treatment fluid that is

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Page 14 of 54 effective for the expulsion of drilling fluid, for example, in spacer fluid embodiments. In some cases, furnace dust can be used to produce a treatment fluid with a low degree of thermal dilution. For example, the treatment fluid may even have a yield point that increases at elevated temperatures such as those found downhole.

Furnace dust may be included in the spacer fluids in an amount sufficient to produce, for example, the intended Theological properties. The concentration of the kiln powder can also be selected to produce a low-cost replacement for higher-cost additives such as Portland cement, which may typically be included in a given treatment fluid. In some embodiments, the furnace dust may be present in a treatment fluid in an amount in the range of about 1% to about 65% by weight of the treatment fluid (e.g., about 1%, about 5% , approximately 10%,

<td>approximately</td><td> 15%,</td><td>approximately</td><td> 20%,</td><td>approximately</td><td> 25%,</td>

<td>approximately</td><td> 30%,</td><td>approximately</td><td> 35%.</td><td>approximately</td><td> 40%,</td>

<td>approximately</td><td> 45%,</td><td>approximately</td><td> 50%.</td><td>approximately</td><td> 55%,</td>

approximately 60%, approximately 65%, etc.). In some embodiments, the furnace dust may be present in the treatment fluid in an amount in the range of about 5% to about 60% by weight of the treatment fluid. In some embodiments, the furnace dust may be present in an amount in the range of about 20% to about 35% by weight of the treatment fluid. On the other hand, the amount of kiln dust can be expressed in weight of cementitious components ("bwocc"). In the present context, the term "weight of cementitious components" or "bwocc" refers to the amount of a component

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Page 15 of 54 such as kiln dust, with respect to the total amount of cementitious components used in the 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 so on. . For example, kiln dust may be present in an amount in a range of

<td>approximately 1% to 100% bwocc. (eg.</td><td>, approximately</td><td> 1%,</td>

<td>about 5%, about 10%,</td><td>approximately</td><td> 20%,</td>

<td>about 30%, about 40%,</td><td>approximately</td><td> 50%,</td>

<td>about 60%, about 70%,</td><td>approximately</td><td> 80%,</td>

approximately 90%, 100%, etc.). In some embodiments, the kiln dust may be present in an amount in the range of about 60% to 100% and, on the other hand, about 80% to 100% bwocc. A person of ordinary skill in the art, with the benefit of this disclosure, should recognize the appropriate amount of kiln powder to include for a chosen application.

The water used in one embodiment of the treatment fluids may include, for example, fresh water, salt water (e.g., water containing one or more salts dissolved therein), brine (e.g., water saturated salt produced by an underground formation), sea water, any combination thereof. In general, water can be of any origin as long as it does not contain an excess of compounds that could adversely affect the other components of the treatment fluid. Water may be included in an amount sufficient to form a pumpable fluid. In some embodiments, water may be included in the treatment fluids in an amount ranging from about 40% to

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Page 16 of 54 approximately 200% bwocc. In some embodiments, it may be included in an amount ranging from about 40% to about 150% bwocc.

Optionally, embodiments of the treatment fluids may also comprise fly ash. A variety of fly ashes may be suitable, including fly ash classified as Class C or Class F fly ash according to the American Petroleum Institute, API Specification for Materials and Testing for Well Cements, API Specification 10, Fifth Ed., 1 July 1990. Suitable examples of fly ash include, but are not limited to, the cement additive POZMIX® A, available from Halliburton Energy Services. Inc., Duncan. Oklahoma. If used, fly ash can usually be included in the treatment fluids in an amount suitable for a specific application. In some embodiments, the fly ash may be present in an amount ranging from about 1% to about 99% bwocc (e.g., about 1%, about 5%, about 10%, about 20%, about 30 %, approximately 40%, approximately 50%, approximately 60%, approximately 70%, approximately 80%, approximately 90%, approximately 99%, etc.). In some embodiments, fly ash may be present in an amount in the range of about 1% to about 20% and, on the other hand, from about 1% to about 10% bwocc. A person of ordinary skill in the art, with the benefit of this disclosure, should recognize the appropriate amount of fly ash to include for a chosen application.

Optionally, embodiments of the treatment fluids may further comprise barite. In some embodiments, the barite

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Page 17 of 54 can be a barite of specific size. Size-specific barite generally refers to barite that has been separated, sieved, ground, or otherwise sized to produce barite with an intended particle size. For example, barite can be sized to have a particle size less than about 200 microns. If used, barite can generally be included in the treatment fluids in an amount suitable for a specific application. For example, barite may be present in an amount ranging from about 1% to about 99% bwocc (e.g., about 1%, about 5%, about 10%, about 20%, about 30%, about 40 %, approximately 50%, approximately 60%, approximately 70%, approximately 80%, approximately 90%, approximately 99%, etc.). In some embodiments, barite may be present in an amount in the range of about 1% to about 20% and, on the other hand, from about 1% to about 10% bwocc. A person of ordinary skill in the art, with the benefit of this disclosure, should recognize the appropriate amount of barite to include for a chosen application.

Optionally, embodiments of the treatment fluids may further comprise pumicite. In general, pumicite is a volcanic rock that can exhibit cementitious properties due to the fact that it can set and harden in the presence of hydrated lime and water. Hydrated lime can be used in combination with pumicite, in some embodiments. If used, pumicite can generally be included in the treatment fluids in an amount suitable for a specific application. For example, pumicite may be present in an amount ranging from about 1% to about 99% bwocc (e.g., about

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Page 18 of 54

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, pumicite may be present in an amount in the range of about 1% to about 20% and, on the other hand, from about 1% to about 10% bwocc. A person of ordinary skill in the art, with the benefit of this disclosure, should recognize the appropriate amount of pumicite to include for a chosen application.

Optionally, the treatment fluid embodiments may further comprise a free water control additive. In the present context, the term “free water control additive” refers to an additive included in a liquid to, among other things, reduce (or prevent) the presence of free water in the liquid. Free water control additives can also reduce (or prevent) settling of solids. Examples of 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-1015™ suspending agent, available from Halliburton Energy Services, Inc. Another example of a suitable free water control additive is WG-17™ solid additive, available from Halliburton. Energy Services, Inc. The free water control additive may be present in the form of a dry solid in some embodiments. If used, the free water control additive may be present in an amount in the range of about 0.1% to about 16% bwocc, for example. In embodiments

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Page 19 of 54 alternatives, the free water control additive may be present in an amount in the range of about 0.1% to about 2% bwocc.

In some embodiments, the treatment fluids may further comprise a lightweight additive. The lightweight additive may be included to reduce the density of the treatment fluid embodiments. For example, the lightweight additive can be used to form a treatment fluid, for example, with a density less than about 13 ppg (1557.7 kg/m³). The light additive may typically have a specific gravity of less than about 2.0. Examples of suitable lightweight additives may include sodium silicate, hollow microspheres, gilsonite, perlite and combinations thereof. An example of a suitable sodium silicate is the ECONOLITE™ additive, sold by Halliburton Energy Services, Inc. If used, the light additive may be present in an amount in the range of 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 about 1% to about 10% bwocc.

As mentioned above, treatment fluid embodiments may be foamed with a gas, for example, to produce a treatment fluid with reduced density. It is to be understood that reduced densities may be necessary in displacement embodiments to more closely match the density of a given drilling fluid, for example, in the case of using lightweight drilling fluids. Drilling fluid 126 can be considered light if it has a density of less than about 13 ppg (1557.7 kg/m³). or less than about 10 ppg (1198.2 kg/m³), or otherwise less than approximately 9 ppg (1078.4 kg/m³). In some embodiments, the

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Page 20 of 54 treatment fluids can be foamed to have a density within approximately 10% of the density of the drilling fluid 126 and. on the other hand, within approximately 5% of the density of the drilling fluid 126. Although techniques, such as light additives, can be used to reduce the density of treatment fluids comprising furnace dust without foaming them, These techniques have disadvantages. For example, reducing the density of the treatment fluid to less than about 13 ppg (1557.7 kg/m³) using light additives can produce unstable slurries, which can present problems with the sedimentation of solids, the flotation of light additives and free water, among others. Consequently, the treatment fluid can be foamed to produce a treatment fluid with reduced density that is more stable.

Therefore, in some embodiments, the treatment fluids may be foamed and comprise water, kiln powder, a foaming agent, and a gas. Optionally, to produce a treatment fluid with lower density and more stable foam, the treatment fluid may further comprise a lightweight additive, for example. With the lightweight additive, a base slurry can be prepared which can then be foamed to produce an even lower density. In some embodiments, the foamed treatment fluid may have a density in the range of about 4 ppg to about 13 ppg (about 479.3 to about 1557.7 kg/m³), or from about 7 ppg to about 9 ppg (from about 838.7 to about 1078.4 kg/m). In a specific embodiment, a base slurry may be foamed of a density in the range of about 9 ppg to about 13 ppg (about 838.7 to about 1078.4 kg/m³).

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The gas used in the foamed treatment fluid embodiments may be any gas suitable for foaming the treatment fluid, including, but not limited to, air, nitrogen, and combinations thereof. In general, gas must be present in embodiments of foamed treatment fluids in an amount sufficient to form the intended foam. In certain embodiments, the gas may be present in an amount ranging from about 5% to about 80% by volume of the foamed treatment fluid at atmospheric pressure, or from about 5% to about 55% by volume and, on the other hand, from about 15% to about 30% by volume.

If foamed, the treatment fluid embodiments may comprise a foaming agent to produce a suitable foam. In the present context, the term “foaming agent” refers to a material (e.g., a surfactant) or a combination of materials that facilitates the formation of a foam in a liquid, for example, by reducing surface tension. Any suitable foaming agent can be used to form a foam in an aqueous liquid in the treatment fluid embodiments. Examples of 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 alken amidopropyl betaine surfactant and an alkyl or alken dimethylamine oxide surfactant;

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Page 22 of 54 aqueous solutions of an alpha-olefinic sulfonate surfactant and a betaine surfactant and combinations thereof. An example of a suitable foaming agent is FOAMER™ 760 foamer/stabilizer, available from Halliburton Energy Services, Inc. Generally, the foaming agent may be present in foamed treatment fluid embodiments in an amount sufficient to produce a suitable foam. In some embodiments, the foaming agent may be present in an amount in the range of about 0.8% to about 5% by volume of water (bvow").

A wide variety of additional additives may be included in the treatment fluids that a person skilled in the art deems appropriate, with the benefit of this disclosure. Examples of such additives include, but are not limited to, supplemental cementitious materials, weighting agents, viscosifying agents (e.g., clays, hydratable polymers, guar gum), fluid loss control additives, against lost circulation, filtration control additives, dispersants, corrosion inhibitors, scale inhibitors, formation conditioning agents and surfactants for water wetting. Water wetting surfactants can be used to remove oil from existing wellbore surfaces (e.g., casing) to improve cement and consolidate spacer fluid adhesion. Examples of suitable weighting agents include, for example, materials having a specific gravity of 3 or more, such as barite. Specific examples of these and other additives include; organic polymers, biopolymers, latex, ground rubber, surfactants, crystalline silica, amorphous silica, silica flour, fumed silica, nanoclays (e.g., clays having at least one dimension less than 100 nm), salts, fibers,

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Page 23 of 54 hydratable clays, microspheres, rice husk ash, microfine cement (e.g., cement with an average particle size of 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 combination thereof and so on. In some embodiments, a supplemental cementitious material may be included in the treatment fluid in addition to or instead of all or a portion of the kiln powder. Examples of suitable supplemental cementitious materials include, but are not limited to, Portland cement, Portland cement interground with pumice, microfine cement, fly ash, slag, pumicite, gypsum, and any combination thereof. A person of ordinary skill in the art, having the benefit of this disclosure, should easily determine the type and amount of additive useful for a specific application and intended result. It is to be understood that, although 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 cited additives.

As mentioned above, embodiments of the treatment fluids (e.g., cement composition 142, spacer fluid 140, etc.) can be consolidative, since the treatment fluids can develop a gel strength and /or compressive strength in well 118. Consolidation is defined, in this context, as one of three types of behavior. Type 1 consolidation can be identified as a gelled fluid that can be displaced and/or pumped when the hydraulic shear stress exceeds the yield point (YP) of the gel. Type 2 consolidation can be identified as a plastic semisolid that can experience “plastic deformation if shear stress, compressive strength, or

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Page 24 of 54 tensile strength exceeds the “plastic yield limit”. Type 3 consolidation can be identified as a rigid solid similar to normal setting cement. During a constant progressive strain rate during conventional compressive strength testing, both confined and unconfined, a Type 3 consolidated material would exhibit Hookean linear elastic strain and stress behavior, followed by some plastic yielding failure and/or or mechanical. The treatment fluid can be transformed from the pumpable fluid that was placed during the normal displacement operation to Type 1 and/or continue to progress to Type 2 and/or subsequently progress to Type 3. It is to be understood that the consolidation of the treatment fluid It is under well conditions and, as those of ordinary skill in the art will appreciate, well conditions may vary. However, treatment fluid embodiments may be characterized by exhibiting Type 1, Type 2, or Type 3 consolidation under certain well conditions.

Specific examples of how to characterize a Type 1 consolidation include measuring the yield point. Type 1 consolidation exhibits a YP of about 25 Pascals to about 250 Pascals, where the YP is measured by one of the methods described in US Patent No. 6,874,353, that is: employing a series of parallel vertical blades on a rotor axis, what those skilled in the art call the “Reel Method”; or using a new device and method also described in United States Patent No. 6,874,353. Another method used to define the YP of Type 1 consolidation is that defined by Morgan, RG, Suter, DA and Sweat, VA, Mathematical Analysis of a Simple Back Extrusion Rheometer, ASAE Paper No. 79-6001. Additionally, other methods commonly used by people with diabetes can be used.

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Page 25 of 54 training in the technique to define the YP of the treatment fluid with Type 1 consolidation. On the other hand, another method to characterize a Type 1 consolidation includes measuring the gel strength of the material, which can be defined as Static Gel Strength” (SGS) as defined and measured in accordance with API Recommended Practice on Determining the Static Gel Strength of Cement Formations, ANSI/API Recommended Practice 10B-6. A Type 1 consolidation may exhibit SGS values ​​of approximately 70 lbf/100 ft² at approximately 500 lbf/100 ft² (from about 0.03 kPa to about 0.23 kPa)

Specific examples of how to characterize a Type 2 consolidation include measuring the yield stress in compression (YL-C). The YLC refers to a compressive stress at which the material undergoes permanent deformation. Permanent deformation refers to a measurable strain stress that does not return to zero in a period of time that is on the same order of magnitude as the total time required to carry out the measurement. EIYL-C can vary from 1 psi (Ibf/in²) to 2,000 psi (0.006 to 13.78 MPa), where the most common values ​​are in a range of 5 psi to 500 psi (0.034 to 13.78 MPa).

Specific examples of how to characterize a Type 3 consolidation include measuring compressive strength. Type 3 consolidation typically exhibits unconfined uniaxial compressive strengths in the range of about 5 psi (0.34 MPa) to about 10,000 psi (68.94 MPa), while the most common values ​​are typically in the range from approximately 10 psi (6.89 MPa) to approximately 2,500 psi (17.23 MPa). These values ​​are reached in 7 days or less. Some formulations can be designed to provide significant compressive strengths within 24 hours to 48 hours. The geometry and typical sizes of samples for

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Page 26 of 54 measurements are similar, but not limited, to those used to characterize oil well cements: 2-inch (5 cm) cubes or 2-inch diameter (5 cm) cylinders with a length of 4 inches (10 cm) or 1-inch diameter (2.54 cm) cylinders with a length of 2 inches (5 cm); as well as other methods known to people trained in the technique of measuring the “mechanical properties” of oil well cements. For example, compressive strength can be determined by crushing samples in a compression testing machine. Compressive strength is calculated from the load at failure 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.

As a specific example of consolidation, when left in an annular space 130 (e.g., between the walls of the wellbore 118 and the casing 108 or between the casing 108 and a larger conduit disposed in the wellbore 118 ), the treatment fluid may consolidate to develop a static gel strength and/or compressive strength. The consolidated mass formed in the annulus 130 may act to support and hold in position the casing 108 in the wellbore 118 and adhere the outer surface of the casing 108 to the walls of the wellbore 118 or to the larger conduit. The consolidated mass formed in the annulus 130 may also constitute a substantially impermeable barrier to isolate 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.

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Page 27 of 54

In some embodiments, consolidation of the treatment fluid (e.g., spacer fluid 140 or cement composition 142) in well 118 may be measured. Measurement of consolidation may also include measurement of the integrity of the wellbore 118. bond formed between the consolidated treatment fluid and the outer wall of the casing 108 and/or between the consolidated fluid and the walls of the well 118 or the larger conduit provided in the well 118. In some embodiments, data corresponding to the integrity of this adhesion can be collected and the data can be recorded in a record commonly known as an adhesion profile." The adhesion profile can be used, for example, to analyze the consolidation properties of the treatment fluid in well 118. Accordingly, embodiments may include performing a cement adhesion profile in at least the portion of the well 118 that contains the consolidated treatment fluid. The cement adhesion profile corresponding to the consolidated treatment fluid can be obtained by any method used to measure integrity without limitation. In some embodiments, a tool, on a cable, may be run into the wellbore 118 that can detect adhesion of the consolidated treatment fluid to the casing 108 and/or to the walls of the wellbore 118 (or the conduit). larger size). An example of a suitable tool includes an ultrasound tool.

Embodiments of the treatment fluids (e.g., spacer fluid 140) may have a transition time shorter than the transition time of another fluid (e.g., cement composition 142) subsequently introduced into the well 118. The term transition time,” used in this context, refers to the time in which a fluid progresses from a static gel strength of approximately 100 lbf/100 ft² (0.05 kPa) to approximately

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Page 28 of 54

500 lbf/100 ft² (0.24 kPa). By having a shorter transition time, the treatment fluid can reduce or even prevent gas migration in the well 118, even if the gas migrates through the subsequently introduced cement composition 124 before it has developed a gel strength. enough to prevent said. Gas and liquid migration can generally be prevented at a static gel strength of 500 lbf/100 ft.² (0.24 kPa). By reducing the amount of gas that can migrate through well 118, the subsequently added cement composition 142 can progress through its slower transition period without gas migration, which is a significant factor as the cement develops strength. static gel. Some embodiments of treatment fluids may have a transition time (i.e., the time it takes to progress from a static gel strength of approximately 100 lbf/100 ft.² (0.05 kPa) at approximately 500 lbf/100 ft² (0.24 KPa) at well conditions of approximately 45 minutes or less, approximately 30 minutes or less, approximately 20 minutes or less or approximately 10 minutes or less. Treatment fluid embodiments also rapidly develop static gel strengths of approximately 100 lbf/100 ft.²(0.05 kPa) and approximately 500 lbf/100 ft² (0.24 kPa), respectively, at well conditions. The time it takes for a fluid to develop a static gel strength of approximately 100 lbf/100 ft² (0.05 kPa) is also called zero gel time.” For example, treatment fluids may have a zero gel time at well conditions of about 8 hours or less, and, on the other hand, about 4 hours or less. In some embodiments, the treatment fluids may have a zero gel time ranging from about 0 minutes to about 4 hours or more. As a further example, fluids from

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Page 29 of 54 treatment can develop static gel strengths of approximately 500 lbf/100 ft² (0.23 kPa) or more under well conditions over a period of approximately 10 minutes to approximately 8 hours or more. The times quoted for the development of static gel resists are given in well conditions, those of ordinary skill in the art will understand that specific well conditions (e.g., temperature, pressure, depth, etc.) vary; however, treatment fluid embodiments must meet these specific requirements under well conditions. Static gel strength can 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 according to any suitable technique. In some embodiments, the desired amount of water may be introduced into a mixer (e.g., a cement mixer), followed by the dry mix. The dry mixture may comprise kiln dust and other solid additives, for example. Additional liquid additives, if included, may be added to the water as appropriate before or after combining with the dry mix. This mixture can be stirred for a period of time sufficient to form a slurry. This base slurry can then be introduced into the well 118 by means of pumps (e.g. cementing unit 144), for example. In foamed embodiments, the base slurry may be pumped into the well 118 and a foaming agent may be metered into the base slurry, followed by injection of a gas, e.g., into a "T" to mix foam. , in an amount sufficient to foam the base slurry and thus form a foamed treatment fluid, according to certain embodiments. After foaming, the foamed treatment fluid can be introduced into

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Page 30 of 54 well 118. As those of ordinary skill in the art will appreciate, with the benefit of this disclosure, other techniques may be used for the preparation of treatment fluids in accordance with the present disclosure.

In some embodiments, the methods may include improving the Theological properties of a treatment fluid (e.g., spacer fluid 140, cement composition 142, etc.). The method may comprise including furnace dust in a treatment fluid. The optional additives described above may also be included in the treatment fluid. The furnace dust may be included in the treatment fluid in an amount sufficient to give it a higher yield point than that of a first fluid. The higher yield point may be advantageous, for example, to effectively displace the first fluid from the wellbore. In the present context, the term “yield limit” refers to the resistance of a fluid to initial flow, or represents the effort necessary to initiate fluid movement. In one embodiment, the yield point of the treatment fluid at a temperature of up to about 180°F (82.2°C) is greater than about 5 lb/100 ft.² (0.002 kPa). In one embodiment, the yield point of the treatment fluid at a temperature of up to about 180°F (82.2°C) is greater than about 10 lb/100 ft.²(0.004 kPa). In one embodiment, the yield point of the treatment fluid at a temperature of up to about 180°F (82.2°C) is greater than about 20 lb/100 ft.² (0.008 kPa) It may be desirable that the treatment fluid not be thermally diluted to a lower yield point than the first fluid at elevated temperatures. Consequently, the treatment fluid may have a higher yield stress than the first fluid at elevated temperatures, such as 180°F (82.2°) or at the static temperature of

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Page 31 of 54 bottom hole (“BHST”). In one embodiment, the treatment fluid may have a yield point that increases at elevated temperatures. For example, the treatment fluid may have a higher yield point at 180°F than at 80°F (26.6°C). As an additional example. The treatment fluid may have a higher yield point at the BHST than at 80°F (26.6°C).

In some embodiments, the treatment fluids can be used in the displacement of a drilling fluid 126 from a well 118. The drilling fluid 126 can include, for example, any number of fluids, such as solid suspensions, mixtures and emulsions. In some embodiments, the drilling fluid 126 may comprise an oil-based drilling fluid. An example of a suitable oil-based drilling fluid comprises an inverse emulsion. In some embodiments, the oil-based drilling fluid may comprise an oleaginous fluid. Examples of oleaginous fluids that may be included in oil-based drilling fluids include, but are not limited to, α-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.

To facilitate a better understanding of the present invention, the following examples of certain aspects of some embodiments are presented. In no way should the following examples be construed as limiting, or defining, the full scope of the invention. In the following examples, the concentrations are expressed as a percentage by weight of the total composition.

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Page 32 of 54

EXAMPLE 1

Samples of treatment fluids were prepared to evaluate the Theological properties of spacer fluids containing furnace dust. In this example cement kiln dust was used. The treatment fluid samples were prepared as follows. All dry components (e.g. cement kiln dust, fly ash, bentonite, free water control additive, etc.) were first metered into a glass container with a transparent lid and shaken by hand until that were incorporated. Tap water was then dispensed into a Waring mixing bottle. The dry components were then mixed with water with stirring at 4,000 rpm. The mixer speed was then increased to 12,000 rpm for approximately 35 seconds.

Spacer fluid sample No. 1 was an 11 pounds per gallon (1318 kg/m3) slurry.³) which comprised 60.62% water, 34.17% cement kiln dust. 4.63% fly ash and 0.58% free water control additive (WG-17™ solid additive).

Spacer fluid sample No. 2 was an 11 pounds per gallon (1318 kg/m3) slurry.³) which comprised 60.79% water, 30.42% cement kiln dust. 4.13% fly ash, 0.17% free water control additive (WG-17'“ solid additive), 3.45% bentonite and 1.04% Econolite* additive.

The Theological values ​​were then determined using a Fann Model 35 Viscosimeter. Dial readings were recorded at speeds of 3, 6, 100, 200 and 300 with a B1 coil, an R1 rotor and a 1.0 spring. Dial readings, plastic viscosity, and corresponding yield stress for the spacer fluids were measured in accordance with API Recommended Practices 10B, Bingham plastic model and are recorded

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Page 33 of 54 in the following table. The abbreviation TV” refers to plastic viscosity, while the abbreviation ΎΡ” refers to yield strength.

TABLE 1

<td rowspan="2">fluid sample</td><td rowspan="2">Temp. CF) (°C)</td><td colspan="5">RPM viscometer</td><td rowspan="2">PV (cP)</td><td rowspan="2">YP (Ib/ 100 ft²* (W&gt;e)</td>

<td> 300</td><td> 200</td><td> 100</td><td> 6</td><td> 3</td>

<td rowspan="2"> 1</td><td> 80 (26,6)</td><td> 145</td><td> 127</td><td> 90</td><td> 24</td><td> 14</td><td> 113,3</td><td> 27.4 (1.3)</td>

<td> 180 (82)</td><td> 168</td><td> 143</td><td> 105</td><td> 26</td><td> 15</td><td> 154,5</td><td> 30,3 (1.4)</td>

<td rowspan="2"> 2</td><td> 80 (26,6)</td><td> 65</td><td> 53</td><td> 43</td><td> 27</td><td> 22</td><td> 41,1</td><td> 26,9 (1.24)</td>

<td> 180 (82)</td><td> 70</td><td> 61</td><td> 55</td><td> 22</td><td> 18</td><td> 51,6</td><td> 25.8 (1.23)</td>

The thickening time of fluid sample No. 1 was also determined in accordance with API Recommended Practice 10B at 205° F (96°C). Fluid sample No. 1 had a thickening time of over 6.00+ hours.

Accordingly, the preceding example demonstrates that the addition of cement kiln dust to a treatment fluid can impart properties suitable for use in underground applications. In particular, the preceding example illustrates, among other things, that cement kiln dust can be used to produce a treatment fluid that may not exhibit thermal dilution with the treatment fluid potentially even having a yield point that increases with temperature. For example, fluid sample No. 2 had a higher yield stress at 180° F (82°C) than at 80° F (26.6°C). Furthermore, the yield strength of fluid sample No. 1 it only had a slight decrease at 180° F (82°C) compared to that at 80° F (26.6°C). Furthermore, the example illustrates that the addition of cement kiln powder to a treatment fluid can confer a plastic viscosity that increases with temperature.

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Page 34 of 54

EXAMPLE 2

Other samples of treatment fluids were prepared to further evaluate the Theological properties of the spacer fluids, which contained kiln dust. Cement kiln dust was used in this example. Treatment fluid samples were prepared as follows. First, all dry components (e.g., cement kiln dust, fly ash) were metered into a glass container with a transparent lid and stirred by hand until incorporated. Tap water was then dispensed into a Waring mixing bottle. The dry components were then mixed with water with stirring at 4,000 rpm. The mixer speed was then increased to 12,000 rpm for approximately 35 seconds.

Fluid sample No. 3 was a 12.5 pound per gallon (1497.8 kg/m3) fluid comprising 47.29% water and 52.71% cement kiln dust.

Fluid sample No. 4 was a 12.5 pounds per gallon (1497.8 kg/m3) fluid comprising 46.47% water, 40.15% cement kiln dust, and 13.38% fly ash.

Fluid sample No. 5 was a 12.5 pounds per gallon (1497.8 kg/m3) fluid comprising 45.62% water, 27.19% cement kiln dust, and 27.19% fly ash.

Fluid sample No. 6 was a 12.5 pounds per gallon (1497.8 kg/m3) fluid comprising 44.75% water, 13.81% cement kiln dust, and 41.44% fly ash.

Fluid sample No. 7 (comparative) was a 12.5 pounds per gallon (1497.8 kg/m3) fluid comprising 43.85% water and 56.15% fly ash.

Rheological values ​​were then determined using a Model 35 Fann Viscometer. Dial readings were recorded at speeds of 3, 6, 30, 60, 100, 200, 300 and 600 with a coil B1, a rotor R1 and a spring 1.0 . The dial readings, plastic viscosity and yield stress corresponding to the spacer fluids were measured in accordance with API Recommended Practices 10B, Bingham Plastic Model and are reported

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Page 35 of 54 in the following table. The abbreviation PV” refers to plastic viscosity, while the abbreviation ΎΡ” refers to yield strength.

TABLE 2

<td rowspan="2">fluid sample</td><td rowspan="2">Cement kiln dust to fly ash ratio</td><td rowspan="2">Temp, r η (°C)</td><td colspan="8">RPM viscometer</td><td rowspan="2">PV (cP)</td><td rowspan="2">YP (Ib/ 100 ft²» (Pa)</td>

<td> 600</td><td> 300</td><td> 200</td><td> 100</td><td> 60</td><td> 30</td><td> 6</td><td> 3</td>

<td rowspan="3"> 3</td><td rowspan="3"> 100:0</td><td> 80 (26)</td><td> 33</td><td> 23</td><td> 20</td><td> 15</td><td> 13</td><td> 12</td><td> 8</td><td> 6</td><td> 12</td><td> 11 (5)</td>

<td> 130 (54)</td><td> 39</td><td> 31</td><td> 27</td><td> 23</td><td> 22</td><td> 19</td><td> 16</td><td> 11</td><td> 12</td><td> 19 (9)</td>

<td> 180 (82)</td><td> 66</td><td> 58</td><td> 51</td><td> 47</td><td> 40</td><td> 38</td><td> 21</td><td> 18</td><td> 16,5</td><td> 41,5 (19)</td>

<td rowspan="3"> 4</td><td rowspan="3"> 75:25</td><td> 80 (26)</td><td> 28</td><td> 22</td><td> 19</td><td> 15</td><td> 14</td><td> 11</td><td> 8</td><td> 6</td><td> 10,5</td><td> 11,5 (5.5)</td>

<td> 130 (54)</td><td> 39</td><td> 28</td><td> 25</td><td> 21</td><td> 19</td><td> 16</td><td> 14</td><td> 11</td><td> 10,5</td><td> 17.5 (8.4)</td>

<td> 180 (82)</td><td> 51</td><td> 39</td><td> 36</td><td> 35</td><td> 31</td><td> 26</td><td> 16</td><td> 11</td><td> 6</td><td> 33 (16)</td>

<td rowspan="3"> 5</td><td rowspan="3"> 50:50</td><td> 80 (26)</td><td> 20</td><td> 11</td><td> 8</td><td> 6</td><td> 5</td><td> 4</td><td> 4</td><td> 3</td><td> 7,5</td><td> 3.5 (1.6)</td>

<td> 130 (54)</td><td> 21</td><td> 15</td><td> 13</td><td> 10</td><td> 9</td><td> 8</td><td> 6</td><td> 5</td><td> 7,5</td><td> 7.5 (3.6)</td>

<td> 180 (82)</td><td> 25</td><td> 20</td><td> 17</td><td> 14</td><td> 13</td><td> 12</td><td> 7</td><td> 5</td><td> 9</td><td> 11 (5)</td>

<td rowspan="3"> 6</td><td rowspan="3"> 25:75</td><td> 80 (26)</td><td> 16</td><td> 8</td><td> 6</td><td> 3</td><td> 2</td><td> 1</td><td> 0</td><td> 0</td><td> 7,5</td><td> 0.5 (0.2)</td>

<td> 130 (54)</td><td> 15</td><td> 8</td><td> 6</td><td> 4</td><td> 3</td><td> 2</td><td> 1</td><td> 1</td><td> 6</td><td> 2 (0.9)</td>

<td> 180 (82)</td><td> 15</td><td> 9</td><td> 7</td><td> 5</td><td> 4</td><td> 4</td><td> 2</td><td> 2</td><td> 6</td><td> 3 (1.4)</td>

<td rowspan="3">7 (Comp.)</td><td rowspan="3"> 0:100</td><td> 80 (26)</td><td> 16</td><td> 7</td><td> 5</td><td> 3</td><td> 1</td><td> 0</td><td> 0</td><td> 0</td><td> 6</td><td> 1 (0.5)</td>

<td> 130 (54)</td><td> 11</td><td> 4</td><td> 3</td><td> 1</td><td> 0</td><td> 0</td><td> 0</td><td> 0</td><td> 4,5</td><td> -0,5 (0,23)</td>

<td> 180 (82)</td><td> 8</td><td> 3</td><td> 2</td><td> 0</td><td> 0</td><td> 0</td><td> 0</td><td> 0</td><td> 4,5</td><td> -1,5 _(;07)</td>

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Page 36 of 54

Accordingly, the preceding example illustrates that the addition of cement kiln dust to a treatment fluid can impart properties suitable for use in underground applications. In particular, the preceding example illustrates, among other things, that cement kiln dust can be used to produce a treatment fluid that may not exhibit thermal dilution with the treatment fluid even potentially having a yield stress that increases with the temperature. Furthermore, as illustrated in Table 2 above, higher yield strengths were observed for treatment fluids with higher concentrations of cement kiln dust.

EXAMPLE 3

A sample of treatment fluid containing furnace dust was prepared to compare the Theological properties of a treatment fluid containing furnace dust with an oil-based drilling fluid. In this example, cement kiln dust was used. The fluid sample was prepared as follows. First, all dry components (e.g., cement kiln dust, fly ash, bentonite, etc.) were metered into a glass container with a transparent lid and stirred by hand until incorporated. Tap water was then dispensed into a Waring mixing bottle. The dry components were then mixed with water with stirring at 4,000 rpm. The mixer speed was then increased to 12,000 rpm for approximately 35 seconds.

Fluid sample No. 8 was an 11 pounds per gallon (1318 kg/m3) slurry.³) comprising 60.79% water, 30.42% cement kiln dust, 4.13% fly ash, 0.17% free water control additive (WG-17™ solid additive), 3 .45% bentonite and 1.04% Econolite additive”*.

The oil-based drilling fluid was a 9.1 pounds per gallon (1078 kg/m) oil-based mud.³).

Theological values ​​were then determined using a Fann Model 35 Viscometer. Dial readings were recorded at speeds of 3, 6, 100, 200 and 300 with a B1 coil, an R1 rotor and a 1.0 spring. The dial readings, plastic viscosity and yield stress corresponding to the

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Page 37 of 54 spacer fluid and drilling fluid were measured in accordance with API Recommended Practices 10B, Bingham Plastic Model and are reported in the following table. The abbreviation “PV” refers to plastic viscosity, while the abbreviation ΎΡ” refers to yield strength. The abbreviation “OBM” refers to an oil-based mud.

TABLE 3

<td rowspan="2">fluid sample</td><td rowspan="2">Temp, rf) (»o</td><td colspan="5">RPM Viscometer</td><td rowspan="2">PV (cP)</td><td rowspan="2">YP (Ib/ 100 ft²* (Pa)</td>

<td> 300</td><td> 200</td><td> 100</td><td> 6</td><td> 3</td>

<td rowspan="2"> 8</td><td> 80 (26,6)</td><td> 59</td><td> 50</td><td> 39</td><td> 22</td><td> 15</td><td> 42</td><td> 21,2 (10)</td>

<td> 180 (82)</td><td> 82</td><td> 54</td><td> 48</td><td> 16</td><td> 13</td><td> 65.3</td><td> 17(8)</td>

<td rowspan="2">OBM</td><td> 80 (26,6)</td><td> 83</td><td> 64</td><td> 41</td><td> 11</td><td> 10</td><td> 74.6</td><td> 12,1 (5,8)</td>

<td> 180 (82)</td><td> 46</td><td> 35</td><td> 23</td><td> 10</td><td> 10</td><td> 36.7</td><td> 10,5 (5)</td>

Accordingly, the preceding example illustrates that the addition of cement kiln dust to a treatment fluid can impart properties suitable for use in underground applications. In particular, the preceding example illustrates, among other things, that cement kiln dust can be used to produce a treatment fluid with a yield point higher than that of a drilling fluid even at elevated temperatures. For example, fluid sample No. 8 has a higher yield strength at 180° F (82.2°C) than oil-based mud.

EXAMPLE 4

A foamed treatment fluid (fluid sample 9) was prepared comprising cement kiln dust. First, a base slurry was prepared having a density of 10 ppg (1198 kg/m³) and comprised cement kiln dust, a free water control additive (0.7% by weight of cement kiln dust

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Page 38 of 54 cement kiln), a light additive (4% by weight of cement kiln dust) and fresh water (32.16 gallons (0.12 m³) per 94-pound (42.3 kg) bag of cement kiln dust). The free water control additive was suspension aid SA-1015™. The light additive was ECONOLITE™ additive. Next, a foaming agent (FOAMER™ 760 foamer/stabilizer) was added in an amount of 2% bvow and the base slurry was then mixed in a foam mixing bottle for 4 seconds at 12,000 rpm. The foamed treatment fluid thus obtained had a density of 8.4 ppg (1006 kg/m³). The sink of the foamed treatment fluid thus obtained was then measured using a free fluid testing procedure specified in API Recommended Practice 10B. However, instead of measuring free fluid, the amount of sink was measured after the foamed treatment fluid was held static for a period of 2 hours. The foamed treatment fluid was initially at 200° and was cooled to room temperature over the 2 hour period. The measured slump with respect to this foamed treatment fluid was 5 millimeters.

EXAMPLE 5

Another foamed treatment fluid (fluid sample 10) was prepared comprising cement kiln dust. First, a base slurry was prepared having a density of 10.5 ppg (1258 kg/m³) and comprised cement kiln dust, a free water control additive (0.6% by weight of cement kiln dust), a light additive (4% by weight of cement kiln dust) and fresh water ( 23.7 gallons (0.08 m³) per 94-pound (42.3 kg) bag of cement kiln dust). The free water control additive was suspension aid SA-1015™. The light additive was ECONOLITE™ additive. Next, a foaming agent (a combined hexylene glycol/cocobetaine surfactant) was added in an amount of 2% bvow and the base slurry was then mixed in a foam mixing bottle for 6 seconds at 12,000 rpm. The foamed treatment fluid thus obtained had a density of 8.304 ppg (995 kg/m³). The treatment fluid foamed like this

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Page 39 of 54 obtained had a subsidence of 0 millimeters, measured in accordance with what was described above, in Example 4.

EXAMPLE 6

The following series of tests were carried out to determine the compressive strength of the treatment fluid samples after consolidation. Twenty-two samples, labeled fluid sample 11-32 in the following table, were prepared that had a density of 12.5 ppg (1408 kg/m³) using various concentrations of the additives. The amount of these additives in each fluid sample is indicated in the following table as “% by weight which denotes the amount of the specific component by weight of Additive 1 + Additive 2. The abbreviation “gal/sk in the following table indicates the gallons of a given component per 94 pound (42.3 kg) scoop of Additive 1 and Additive 2.

The cement kiln dust used was supplied by Holcim (USA) Inc., of Ada, Oklahoma. The shale used was provided by Texas Industries, Inc., of Midlothian, Texas. The pumice stone used was DS-200 or DS-300 lightweight aggregate available from Hess Pumice Products, Inc. The silica flour used was SSA-1™ cement additive, available from Halliburton Energy Services, Inc. The coarse silica flour used was SSA-2™ coarse silica flour, from Halliburton Energy Services, Inc. The metakaolin used was MetaMax® metakaolin, from BASF. The amorphous silica used was SILICALITE™ 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 FineCem™ cement, from Halliburton Energy Services, Inc. The fly ash used was POZMIX® cement additive, from Halliburton Energy Services, Inc. The microfine cement used was MICRO MATRIX® cement with an average particle size of 7.5 microns, from Halliburton Energy Services, Inc. The rice hull ash used was supplied by Rice Hull Specialty Products, Stuttgart, Arkansas. The biopolymer used was provided by CP Kelco, San Diego, California. The barite used was supplied by Baroid Industrial Drilling Products. The latex used was Halliburton Energy's Latex 3000™ additive.

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Services, Inc. The ground rubber used was LIFECEM™ 100 cement additive from Halliburton Energy Services, Inc. The nanoclay used was provided by Nanocor Inc. The set retarder used was SCR-100™ cement retarder from Halliburton Energy Services, Inc. SCR100™ cement retarder is a copolymer of acrylic acid and 2-acrylamido-2-methylpropane sulfonic acid.

After preparation, the fluid sample was allowed to cure for seven days in a 2” by 4” (5 cm x 10 cm) metal cylinder that was placed in a 180°F (82.2°F) water bath.^EITHERC) to form set cylinders. Immediately after removal from the water bath, compressive strengths were determined using a mechanical press in accordance with API RP 10B-2. The results of these tests are presented below. The term “cement kiln dust” is abbreviated “CKD” in the following table.

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TABLE4

<td></td><td colspan="3">Additive#!</td><td colspan="2">Additive #2</td><td colspan="2">Additive #3</td><td colspan="2">Delay</td>

<td>Sample-</td><td rowspan="2">Gal/sk water</td><td></td><td></td><td></td><td></td><td></td><td></td><td>forge</td><td>Beef.</td>

<td>fluid flow</td><td>Guy</td><td>% in</td><td rowspan="2">Guy</td><td>% in</td><td rowspan="2">Guy</td><td>% in</td><td>or cement</td><td>Purchase within 7-Days PSI</td>

<td></td><td></td><td></td><td>P·</td><td>P·</td><td>P-</td><td>% in P.</td><td></td>

<td> 11</td><td> 5,72</td><td>CKD Stone</td><td> 50</td><td>Shale</td><td> 50</td><td> —</td><td> —</td><td> 0</td><td> 510</td>

<td> 12</td><td> 4,91</td><td>pumice DS-</td><td> 50</td><td>Lime</td><td> 50</td><td> —</td><td> --</td><td> 1</td><td> 646</td>

<td></td><td></td><td> 200</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td>

<td> 13</td><td> 5,88</td><td>CKD</td><td> 50</td><td>I latin silica</td><td> 50</td><td> —</td><td> —</td><td> 0</td><td> 288</td>

<td> 14</td><td> 6,05</td><td>CKD</td><td> 50</td><td>Mctacaolin</td><td> 50</td><td></td><td> ..</td><td> 0</td><td> 104</td>

<td> 15</td><td> 5,71</td><td>CKD</td><td> 50</td><td>amorphous silica</td><td> 50</td><td> —</td><td> —</td><td> 1</td><td> 251</td>

<td> 16</td><td> 5,13</td><td>CKD</td><td> 50</td><td>Pcrlite</td><td> 50</td><td> ..</td><td> —</td><td> 0</td><td> 1031</td>

<td> 17</td><td> 5,4</td><td>CKD</td><td> 50</td><td>Lime Stone</td><td> 50</td><td> —</td><td> —</td><td> 0</td><td> 58</td>

<td> 18</td><td> 5,49</td><td>CKD</td><td> 50</td><td>pumice DS-</td><td> 50</td><td> —</td><td> —</td><td> 0</td><td> 624</td>

<td></td><td></td><td></td><td></td><td> 200</td><td></td><td></td><td></td><td></td><td></td>

<td> 19</td><td> 6,23</td><td>CKD</td><td> 50</td><td>Human waste</td><td> 50</td><td> —</td><td> —</td><td> 0</td><td> 587</td>

<td> 20</td><td> 5,88</td><td>CKD</td><td> 50</td><td>coarse silica flour</td><td> 50</td><td> —</td><td> —</td><td> 0</td><td> 1018</td>

<td></td><td></td><td></td><td></td><td>Portland Cement</td><td></td><td></td><td></td><td></td><td></td>

<td> 21</td><td> 6,04</td><td>CKD</td><td> 50</td><td>intermole with stone</td><td> 50</td><td> —</td><td> —</td><td> 1</td><td> 1655</td>

<td></td><td></td><td></td><td></td><td>pumice</td><td></td><td></td><td></td><td></td><td></td>

<td> 22</td><td> 5,63</td><td>CKD</td><td> 50</td><td>Fly Ash Stone</td><td> 50</td><td> —</td><td> —</td><td> 0</td><td> 870</td>

<td> 23</td><td> 5,49</td><td>CKD</td><td> 50</td><td>pumice DS-</td><td> 50</td><td></td><td> --</td><td> 0</td><td> 680</td>

<td></td><td></td><td></td><td></td><td> 325</td><td></td><td></td><td></td><td></td><td></td>

<td></td><td rowspan="2"> 5,03</td><td>Ash</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td>

<td> 24</td><td>steering wheel</td><td> 50</td><td>Lime</td><td> 50</td><td> —</td><td> —</td><td> 1</td><td> 170</td>

<td> 25</td><td> 5,65</td><td>Human waste</td><td> 50</td><td>Lime</td><td> 50</td><td> —</td><td></td><td> 1</td><td> 395</td>

<td> 26</td><td> 6,36</td><td>CKD</td><td> 50</td><td>Microfine cement Ash</td><td> 50</td><td> —</td><td> —</td><td> 2</td><td> 788</td>

<td> 27</td><td> 6,08</td><td>CKD</td><td> 80</td><td>shells of</td><td> 20</td><td> --</td><td> —</td><td> 1</td><td> 203</td>

<td></td><td></td><td></td><td></td><td>rice</td><td></td><td></td><td></td><td></td><td></td>

<td> 28</td><td> 5,42</td><td>CKD</td><td> 50</td><td>Biopolymcro</td><td> 50</td><td> —</td><td> —</td><td> 1</td><td> 265</td>

<td> 29</td><td> 7,34</td><td>CKD</td><td> 50</td><td>Baryta</td><td> 50</td><td></td><td> __</td><td> 0</td><td> 21</td>

<td> 30</td><td> 4,02</td><td>CKD</td><td> 100</td><td> ..</td><td> ——</td><td>Latex</td><td> 2</td><td> 1</td><td> 164,6</td>

<td> 31</td><td> 2,71</td><td>CKD</td><td> 100</td><td> —</td><td> —</td><td>Rubber Mol.</td><td> 10</td><td> 1</td><td> 167,6</td>

<td> 32</td><td> 6,15</td><td>CKD</td><td> 100</td><td> —</td><td> —</td><td>NanoClay</td><td> 2</td><td> 0</td><td> 102,5</td>

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Accordingly, the preceding example illustrates that a treatment fluid comprising furnace dust may be suitable for consolidation. For example, 7-day compressive strengths of 1000 psi (6.89 MPa) or even higher were observed for certain sample grouts.

EXAMPLE 7

The following series of tests were carried out to evaluate the thickening times of the treatment fluid samples. For this example, thickening times were determined for Fluid Samples 11-32 of Example 6. As noted below, the compositions for Fluid Samples 11-32 were the same as those of Example 6 except adjusted the concentration of cement setting retarder in certain samples. Thickening time, which is the time it takes for the compositions to reach 70 Bearden consistency units, was determined for each fluid at 230°F (110°C) in accordance with API RP 10B-2. The results of these tests are presented below. The term "cement kiln dust" is abbreviated to "CKD."¹ in the next table.

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TABLE 5

<td>fluid sample</td><td>Gal/sk water</td><td colspan="2">Additive #1 % Type in Ρ·</td><td colspan="2">Additive #2 % in^1,p0 p.</td><td colspan="2">Additive #3 % in Type p.</td><td>Delay Frag. Cem. % in P.</td><td>Weather Espesam. b:min</td>

<td> 11</td><td> 5,72</td><td>CKD Stone</td><td> 50</td><td>Shale</td><td> 50</td><td> —</td><td> —</td><td> 1</td><td> 11:04</td>

<td> 12</td><td> 4,91</td><td>pumice DS-</td><td> 50</td><td>Lime</td><td> 50</td><td> —</td><td> —</td><td> 1</td><td> 0:30</td>

<td></td><td></td><td> 200</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td>

<td> 13</td><td> 5,88</td><td>CKD</td><td> 50</td><td>silica flour</td><td> 50</td><td> —</td><td> —</td><td> 1</td><td> 3:31</td>

<td> 14</td><td> 6,05</td><td>CKD</td><td> 50</td><td>Metakaolin</td><td> 50</td><td> __</td><td> __</td><td> 1</td><td> 3:13</td>

<td> 15</td><td> 5,71</td><td>CKD</td><td> 50</td><td>amorphous silica</td><td> 50</td><td> —</td><td> —</td><td> 1</td><td> 2:15</td>

<td> 16</td><td> 5,13</td><td>CKD</td><td> 50</td><td>Perlite</td><td> 50</td><td> —</td><td> —</td><td> 1</td><td> 7:30</td>

<td> 17</td><td> 5,4</td><td>CKD</td><td> 50</td><td>Lime Stone</td><td> 50</td><td> —</td><td> —</td><td> 1</td><td> 2:42</td>

<td> 18</td><td> 5,49</td><td>CKD</td><td> 50</td><td>pumice DS-</td><td> 50</td><td></td><td> --</td><td> 1</td><td> 10:00</td>

<td></td><td></td><td></td><td></td><td> 200</td><td></td><td></td><td></td><td></td><td></td>

<td> 19</td><td> 6,23</td><td>CKD</td><td> 50</td><td>Human waste</td><td> 50</td><td> ..</td><td> __</td><td> 1</td><td> 8:08</td>

<td> 20</td><td> 5,88</td><td>CKD</td><td> 50</td><td>coarse silica flour</td><td> 50</td><td> —</td><td> —</td><td> 1</td><td>8pm+</td>

<td></td><td></td><td></td><td></td><td>Portland Cement</td><td></td><td></td><td></td><td></td><td></td>

<td> 21</td><td> 6,04</td><td>CKD</td><td> 50</td><td>intermol, with Stone</td><td> 50</td><td> —</td><td> —·</td><td> 1</td><td> 5:58</td>

<td></td><td></td><td></td><td></td><td>pumice</td><td></td><td></td><td></td><td></td><td></td>

<td> 22</td><td> 5,63</td><td>CKD</td><td> 50</td><td>Fly Ash Stone</td><td> 50</td><td> —</td><td> —</td><td> 1</td><td>12 hrs+</td>

<td> 23</td><td> 5,49</td><td>CKD</td><td> 50</td><td>pumice DS-</td><td> 50</td><td> —</td><td></td><td> 1</td><td> 7:30</td>

<td></td><td></td><td></td><td></td><td> 325</td><td></td><td></td><td></td><td></td><td></td>

<td> 24</td><td> 5,03</td><td>fly ash</td><td> 50</td><td>Lime</td><td> 50</td><td> —</td><td> —</td><td> 1</td><td> 3:32</td>

<td> 25</td><td> 5,65</td><td>Human waste</td><td> 50</td><td>Lime</td><td> 50</td><td></td><td> —</td><td> 1</td><td> 4:05</td>

<td> 26</td><td> 6,36</td><td>CKD</td><td> 50</td><td>Microfine cement Ash</td><td> 50</td><td> —</td><td> —</td><td> 2</td><td> 1:30</td>

<td> 27</td><td> 6,08</td><td>CKD</td><td> 80</td><td>shells of</td><td> 20</td><td> —</td><td> —</td><td> 1</td><td>30 hours+</td>

<td></td><td></td><td></td><td></td><td>rice</td><td></td><td></td><td></td><td></td><td></td>

<td> 28</td><td> 5,42</td><td>CKD</td><td> 50</td><td>Biopolym.</td><td> 50</td><td> —</td><td> —</td><td> 1</td><td> 1:35</td>

<td> 29</td><td> 7,34</td><td>CKD</td><td> 50</td><td>Baryta</td><td> 50</td><td> __</td><td> __</td><td> 1</td><td>I8h+</td>

<td> 30</td><td> 4,02</td><td>CKD</td><td> 100</td><td> ——</td><td> —</td><td>Latex</td><td> 2</td><td> 1</td><td> 1:10</td>

<td> 31</td><td> 2,71</td><td>CKD</td><td> 100</td><td> —</td><td> —</td><td>ground rubber</td><td> 10</td><td> 1</td><td>8pm+</td>

<td> 32</td><td> 6,15</td><td>CKD</td><td> 100</td><td> —</td><td> —</td><td>NanoClay</td><td> 2</td><td> 0</td><td> 54:00</td>

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Accordingly, the preceding example illustrates that a settable spacer fluid may have acceptable thickening times for certain applications.

EXAMPLE 8

The following series of tests were carried out to evaluate the rheological properties of the fluid samples. For this example, the rheological properties of fluid samples 11-32 were determined. Rheological values ​​were determined using a Model 35 Fann Viscometer. Dial readings were recorded at speeds of 3, 6, 30, 60, 100,200, 300 and 600 with a B1 coil, an R1 rotor and a 1.0 spring. An additional sample was used for this specific assay. This is fluid sample 33 that comprised barite and 0.5% of a suspending agent by weight of the barite. The suspending agent was SA™-1015, available from Halliburton Energy Services, Inc. Water was included in an amount sufficient to give a density of 1.5 ppg (1318 kg/m³⁾. The rheological properties of sample 33 were measured twice at two different temperatures and the values ​​were averaged by temperature to present the data reported below. Temperature is measured in degrees Fahrenheit. The results of these tests are recorded below.

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TABLE 6

<td rowspan="3">The fluid sample eleven</td><td rowspan="3">Additive #1 Guy CKD</td><td colspan="3">Additive £9</td><td rowspan="3">Additive #3 Guy</td><td rowspan="3">% in P·</td><td rowspan="3">Temp 80 (26.6)</td><td rowspan="3"> 300 29</td><td colspan="6" rowspan="2">RPM viscometer</td><td rowspan="3"> 600 39</td>

<td rowspan="2">% in Ρ· fifty</td><td rowspan="2">Guy Shale</td><td rowspan="2">% in P- fifty</td>

<td rowspan="2"> 200 21</td><td rowspan="2"> 100 14</td><td rowspan="2"> 6 0 1 1</td><td rowspan="2"> 30 9</td><td rowspan="2"> 6 6</td><td rowspan="2"> 3 5</td>

<td></td><td>Stone</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td>

<td> 12</td><td>pumice DS-200</td><td> 50</td><td>Lime</td><td> 50</td><td> —</td><td> —</td><td> 80</td><td> 24</td><td> 17</td><td> 9</td><td> 6</td><td> 5</td><td> 2</td><td> 1</td><td> 48</td>

<td> 13</td><td>CKD</td><td> 50</td><td>silica flour</td><td> 50</td><td> —</td><td> --</td><td> 80</td><td> 16</td><td> 12</td><td> 8</td><td> 6</td><td> 5</td><td> 4</td><td> 3</td><td> 24</td>

<td> 14</td><td>CKD</td><td> 50</td><td>Metakaolin</td><td> 50</td><td> —</td><td> —</td><td> 80</td><td> 36</td><td> 28</td><td> 19</td><td> 1 5</td><td> 12</td><td> 9</td><td> 8</td><td> 64</td>

<td> 15</td><td>CKD</td><td> 50</td><td>amorphous silica</td><td> 50</td><td> —</td><td> —</td><td> 80</td><td> 31</td><td> 24</td><td> 18</td><td> 1 4</td><td> 12</td><td> 10</td><td> 9</td><td> 49</td>

<td> 16</td><td>CKD</td><td> 50</td><td>Perlite</td><td> 50</td><td> —</td><td> —</td><td> 80</td><td> 40</td><td> 34</td><td> 27</td><td> 2 3</td><td> 20</td><td> 15</td><td> 9</td><td> 61</td>

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<td> 17</td><td>CKD</td><td> 50</td><td>Lime</td><td> 50</td><td> —</td><td> —</td><td> 80</td><td> 46</td><td> 41</td><td> 34</td><td> 3 0</td><td> 27</td><td> 16</td><td> 11</td><td> 65</td>

<td> 18</td><td>CKD</td><td> 50</td><td>Pumice stone DS-200</td><td> 50</td><td> —</td><td> —</td><td> 80</td><td> 23</td><td> 19</td><td> 14</td><td> 1 1</td><td> 9</td><td> 7</td><td> 6</td><td> 40</td>

<td> 19</td><td>CKD</td><td> 50</td><td>Human waste</td><td> 50</td><td> --</td><td> —</td><td> 80</td><td> 23</td><td> 20</td><td> 14</td><td> 1 1</td><td> 9</td><td> 6</td><td> 5</td><td> 41</td>

<td> 20</td><td>CKD</td><td> 50</td><td>silica flour</td><td> 50</td><td></td><td></td><td> 80</td><td> 27</td><td> 19</td><td> 12</td><td> 9</td><td> 7</td><td> 4</td><td> 3</td><td> 64</td>

<td></td><td></td><td></td><td>gross</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td>

<td> 21</td><td>CKD</td><td> 50</td><td>Intermol Portland cement. with</td><td> 50</td><td> __</td><td></td><td> 80</td><td> 15</td><td> 10</td><td> 7</td><td> 5</td><td> 3</td><td> 2</td><td> 1</td><td> 18</td>

<td> 22</td><td>CKD</td><td> 50</td><td>Pumice stone Fly ash</td><td> 50</td><td> —</td><td> —</td><td> 80</td><td> 12</td><td> 9</td><td> 6</td><td> 4</td><td> 3</td><td> 2</td><td> 1</td><td> 21</td>

<td> 23</td><td>CKD</td><td> 50</td><td>Pumice stone DS-325</td><td> 50</td><td> —</td><td> —</td><td> 80</td><td> 39</td><td> 32</td><td> 24</td><td> 2 1</td><td> 17</td><td> 12</td><td> 7</td><td> 57</td>

<td> 24</td><td>fly ash</td><td> 50</td><td>Lime</td><td> 50</td><td> —</td><td> —</td><td> 80</td><td> 12</td><td> 9</td><td> 6</td><td> 4</td><td> 3</td><td> 2</td><td> 2</td><td> 24</td>

<td> 25</td><td>Human waste</td><td> 50</td><td>Lime</td><td> 50</td><td></td><td> __</td><td> 80</td><td> 15</td><td> 10</td><td> 5</td><td> 3</td><td> 2</td><td> 1</td><td> 1</td><td> 23</td>

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<td> 26</td><td>CKD</td><td> 50</td><td>Microfine cement Ash</td><td> 50</td><td> —</td>

<td> 27</td><td>CKD</td><td> 80</td><td>rice husks</td><td> 20</td><td> —</td>

<td> 28</td><td>CKD</td><td> 50</td><td>Biopolym.</td><td> 50</td><td> —</td>

<td> 29</td><td>CKD</td><td> 50</td><td>Baryta</td><td> 50</td><td> —</td>

<td> 30</td><td>CKD</td><td> 100</td><td> —</td><td> —</td><td>Latex</td>

<td> 31</td><td>CKD</td><td> 100</td><td> —</td><td> —</td><td>Ground Rubber</td>

<td> 32</td><td>CKD</td><td> 100</td><td> —</td><td> —-</td><td>NanoClay</td>

<td> 33</td><td>Baryta</td><td> 100</td><td> —</td><td> —</td><td>SA™1015</td>

<td> 33</td><td>Baryta</td><td> 100</td><td> —</td><td> —</td><td>SA™- 1015</td>

<td> —</td><td> 80</td><td> 10</td><td> 7</td><td> 4</td><td> 3</td><td> 2</td><td> 1</td><td> 0</td><td> 14</td>

<td> --</td><td> 80</td><td> 24</td><td> 15</td><td> 9</td><td> 7</td><td> 5</td><td> 3</td><td> 2</td><td> 41</td>

<td> —</td><td> 80</td><td> 175</td><td> 111</td><td> 53</td><td> 3 1</td><td> 15</td><td> 4</td><td> 3</td><td> 220</td>

<td> —</td><td> 80</td><td> 48</td><td> 40</td><td> 30</td><td> 2 6</td><td> 22</td><td> 15</td><td> 13</td><td> 2</td>

<td> 2</td><td> 80</td><td> 48</td><td> 39</td><td> 28</td><td> 2 3</td><td> 19</td><td> 17</td><td> 15</td><td> 82</td>

<td> 10</td><td> 80</td><td> 65</td><td> 56</td><td> 42</td><td> 4 0</td><td> 39</td><td> 30</td><td> 22</td><td> 105</td>

<td> 2</td><td> 80</td><td> 22</td><td> 18</td><td> 12</td><td> 1 0</td><td> 8</td><td> 6</td><td> 5</td><td> 37</td>

<td> 0.5</td><td> 80</td><td> 41</td><td> 36. 5</td><td> 30. 5</td><td> 2 8</td><td> 25. 5</td><td> 20. 5</td><td> 18. 5</td><td>NA</td>

<td> 0.5</td><td> 180</td><td> 38</td><td> 35.</td><td> 32</td><td> 3</td><td> 28</td><td> 23.</td><td> 22</td><td>NA</td>

<td></td><td> (82,2)</td><td></td><td> 5</td><td></td><td> 0</td><td></td><td> 5</td><td></td><td></td>

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Page 4 8 of 54

Accordingly, the preceding example indicates that a treatment fluid may have acceptable Theological properties for a specific application.

EXAMPLE 9

The next series of tests was carried out to further evaluate the compressive strength of the treatment fluid samples. Ten samples, labeled fluid sample 34-43 in the following table, were prepared with a density of 13 ppg (1557 kg/m³) using various concentrations of additives. The amount of these additives in each sample is indicated in the following table as % by weight", which indicates the amount of the specific component by weight of the dry solids, that is, the kiln dust, the Portland cement, the cement accelerator, fly ash and/or lime. The abbreviation “gal/sk” in the following table indicates the gallons of the specific component per 94 pound (42.3 kg) bag of dry solids. The term “cement kiln dust” is abbreviated to “CKD” in the following table.

The cement kiln dust used was Mountain cement kiln dust from Laramie Wyoming, except for fluid sample 43 which used cement kiln dust from Holcim (USA) Inc., Ada, Oklahoma. The Portland cement used in fluid samples 34 and 35 was CEMEX Type 3 Portland cement, from CEMEX USA. The cement accelerator used in fluid sample 34 was CAL-SEAL™ Accelerator, from Halliburton Energy Services Inc. CAL-SEAL™ Accelerator is gypsum. The Class F fly ash used in Slurries 37-41 was supplied by Coal Creek Station. The Class F fly ash used in Slurry 36 was from LaFarge North America.

After preparation, the samples were allowed to cure for twenty-four to forty-eight hours in a 2 by 4” (5 cm x 10 cm) metal cylinder that was placed in a 160°F (8°C) water bath. C) to form set cylinders. For certain samples, cylinders were cured for twenty-four to forty-eight hours, 2” by 4” (5 cm x 10 cm) metal cylinders that were placed in a 180°F (82. 2°C) to form set cylinders. Immediately after removing the water bath, the

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Page 49 of 54 compressive strengths using a mechanical press in accordance with API RP 10B-2. The results of these tests are presented below.

TABLE 7

<td>The fluid sample</td><td>Gal/sk water</td><td>CKD % in P·</td><td>Portland cement % in p.</td><td>Ace! Cemt. % in P.</td><td>Cen. vo! Class F% in p.</td><td>Cen. vol. Class C %in P·</td><td>Cal % in P·</td><td>Comp. Res. 24h PSI (MPa)</td><td>Comp. Res. 24 48 h PSI (MPa)</td>

<td> 34</td><td> 8,75</td><td> 85</td><td> 10</td><td> 5</td><td> 0</td><td> 0</td><td> 0</td><td> 73,4 (0,5)</td><td> —</td>

<td> 35</td><td> 8,75</td><td> 90</td><td> 10</td><td> 0</td><td> 0</td><td> 0</td><td> 0</td><td> 99,8 (0,68)</td><td> —</td>

<td> 36</td><td> 8,14</td><td> 70</td><td> 0</td><td> 0</td><td> 0</td><td> 30</td><td> 0</td><td> 210 (1,44)</td><td> —</td>

<td> 37</td><td> 8,25</td><td> 70</td><td> 0</td><td> 0</td><td> 25</td><td> 0</td><td> 5</td><td> 388 (2,7)</td><td> —</td>

<td> 38</td><td> 8,20</td><td> 75</td><td> 0</td><td> 0</td><td> 21</td><td> 0</td><td> 4</td><td> 300 (2,06)</td><td> 784 (5,40)</td>

<td> 39</td><td> 8,27</td><td> 80</td><td> 0</td><td> 0</td><td> 17,5</td><td> 0</td><td> 2,5</td><td> 224 (1,54)</td><td> 641 (4,42)</td>

<td> 40</td><td> 9,61</td><td> 70</td><td> 0</td><td> 0</td><td> 25</td><td> 0</td><td> 5</td><td> 219 (1,50)</td><td> 567 (3,90)</td>

<td> 41</td><td> 11,5</td><td> 70</td><td> 0</td><td> 0</td><td> 25</td><td> 0</td><td> 5</td><td> 165 (1,13)</td><td> 369 (2,54)</td>

<td> 42</td><td> 5,12</td><td> 100</td><td> 0</td><td> 0</td><td> 0</td><td> 0</td><td> 0</td><td> 36,2 (0,24)</td><td> —</td>

<td> 43</td><td> 5,12</td><td> 100</td><td> 0</td><td> 0</td><td> 0</td><td> 0</td><td> 0</td><td> 60,8 (0,42)</td><td> —</td>

Accordingly, the preceding example illustrates that a treatment fluid may have acceptable compressive strengths for certain applications.

EXAMPLE 10

The following series of tests were carried out to evaluate the development of static gel strength of the treatment fluid samples. Two samples were prepared, labeled fluid samples 44 and 45 with a density of 11 and 13.5 ppy (1318 and 1617 kg/m³) respectively, using various concentrations of additives. The concentrations of the components in each sample are as follows:

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In the case of fluid sample 44, the sample comprised a mixture of cement kiln dust (80% by weight), fly ash (16% by weight) and hydrated lime (4% by weight). The sample also comprised a suspension auxiliary agent in an amount of 0.4% by weight of the mixture. Enough water was included in the sample to produce a density of 11 ppg (1318 kg/m³). The cement kiln dust used was from Holcim (USA) Inc., Ada, Oklahoma. The fly ash used was POZMIX® cement additive, available from Halliburton Energy Services, Inc. The suspending agent was SA™1015 suspending agent, available from Halliburton Energy Services, Inc.

In the case of fluid sample 45, the sample comprised a mixture of cement kiln dust (80% by weight), fly ash (16% by weight) and hydrated lime (4% by weight). Enough water was included in the sample to produce a density of 13.5 ppg (1617 kg/m³). The cement kiln dust used was from Holcim (USA) Inc., Ada, Oklahoma. The fly ash used was the POZMIX® cement additive, marketed by Halliburton Energy Services, Inc.

The static gel strength of the samples was measured in accordance with API Recommended Practice on Determining the Static Gel Strength of Cement Formations, ANSI/API Recommended Practice 10B-6. FIGS. 1 and 2 show static gel strength measurements for fluid samples 44 and 45, respectively, as a function of time. As seen in the figures, the samples progress through the transition time, which is defined as the time between 100 SGS and 500 SGS, very quickly, with a total transition time of 19 minutes in the case of sample 34 and 6 minutes in sample 35. These short transition times are faster than in most cement compositions.

EXAMPLE 11

The following tests were carried out to further evaluate the static gel strength development of the treatment fluid samples. Two samples were prepared, labeled Fluid Samples 46 and 47 with a density of 13.002 and 10.999 ppg (1558 and 1318 kg/m³)

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Page 51 of 54 respectively, using various concentrations of additives. The concentrations of the components in each sample are as follows:

In the case of fluid sample 46, the sample comprised a mixture of cement kiln dust (100% by weight), POZMIX® cement additive (50% by weight of cement kiln dust), cement retarder H® -601 (1% by weight of cement kiln dust), cement retarder H®-25 (0.6% by weight of cement kiln dust) and antifoam D-Air 5000™ (0.5% by weight of cement kiln dust). weight of cement kiln dust). Enough water was included in the sample to produce a density of 13.002 ppg (1558 kg/m³). The cement kiln dust used was from Holcim (USA) Inc., Ada, Oklahoma. The fly ash used was the cement additive POZMIX®, marketed by Halliburton Energy Services, the cement retarder Inc. H®-601 was from Halliburton Energy Services, the cement retarder Inc. H®-25 was from Halliburton Energy Services, Inc. D-Air 5000™ antifoam was from Halliburton Energy Services, Inc.

In the case of fluid sample 47, the sample comprised a mixture of cement kiln dust (100% by weight), SA-1015 (0.4% by weight of cement kiln dust) and the antifoam D- Air 5000™ (0.5% by weight of cement kiln dust). Enough water was included in the sample to produce a density of 10.999 ppg (1318 kg/m³). The cement kiln dust used was from Holcim (USA) Inc., Ada, Oklahoma. SA™-1015 suspending agent was from Halliburton Energy Services, D-Air 5000™ antifoam Inc. was from Halliburton Energy Services, Inc.

The static gel strength of the samples was measured in accordance with API Recommended Practice on Determining the Static Gel Strength of Cement Formations, ANSI/API Recommended Practice 10B-6. Table 8 shows the static gel strength measurements for Fluid Samples 46 and 47, respectively.

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TABLE 8

<td>Fluid Sample 46</td><td>Temp (°F) 220</td><td>Time to reach 100 lbf/100 ft⁸(0.0047 kP») (h:min) 3:25</td><td>Time to arrive 500 IbfflOO foot⁸(0.23 kPa) (h:min) 5:04</td><td>Difference between 100 lbf/100 ft⁸ and 500 lbf/100 ft (h:min) 1:39</td>

<td> 47</td><td> 220</td><td> 3:07</td><td> 3:17</td><td> 00:10</td>

As seen in the table, fluid sample 47 progresses through the transition time, which is defined as time between 100 SGS and 500 SGS, very quickly with a total transition time of 10 minutes. Fluid sample 46 is much slower, taking one hour to go through the transition time. The short fluid sample transition time 47 faster than in most cement compositions.

It is to be understood that, while the compositions and methods are described in terms of comprising, containing or including "various components or steps, the compositions and methods may also essentially consist of" or consist of the various components or steps. Furthermore, the indefinite articles “a” or “an” used in claims to one or more than one of the elements they introduce.

For the sake of brevity, only certain ranges are explicitly displayed here. However, ranges from any lower limit may be combined with any upper limit to indicate a range not specifically mentioned, just as ranges from any lower limit may be combined with any other lower limit to indicate a range not explicitly mentioned, and likewise Similarly, ranges from any upper limit may be combined with any other upper limit to indicate a range not expressly cited. Furthermore, whenever a numerical range with a lower limit and an upper limit is stated, any number and

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Page 53 of 54 any included range that falls within that range. In particular, it is to be understood that any range of values ​​(in the form of aab" or equivalently, approximately aa approximately b" or equivalently, approximately aab" or equivalently, "around aab") indicates every number and range covered within the broader range of values ​​even if it is not mentioned exhaustively. Accordingly, each individual point or value may serve as its own lower or upper limit combined with any other individual point or value or any other lower or upper limit, to indicate a range not explicitly stated.

Therefore, the present invention is favorably adapted to obtain the aforementioned purposes and advantages, as well as those that are inherent thereto. The specific embodiments set forth above are only illustrative, since the present invention can be modified and put into practice in different, although equivalent, ways, obvious to people trained in the art, taking advantage of the concepts presented here. While individual embodiments are described, the invention covers and contemplates all combinations of each embodiment. Furthermore, no limitations are intended to be established as to the details of construction or design set forth herein, other than those described in the following claims. Furthermore, the terms of the claims have their normal plain meaning, unless the patent owner explicitly and clearly defines otherwise. It is evident, therefore, that the specific illustrative embodiments set forth above may be altered or modified and that all such variations are considered to be within the scope and spirit of the present invention. In the event of a conflict as to the use of a term in this specification, and one or more patents or other documents that may be incorporated herein by reference, definitions that are compatible with this specification should be adopted.

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<img file="AR115902A2_D0001.tif" />

Argentine Republic - National Executive Branch 2020 - Year of General Manuel Belgrano

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Number: IF-2020-86224933-APN-ANP#INPI

BUENOS AIRES CITY

Friday, December 11, 2020

Reference: 20190102205

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National Institute of Industrial Property

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Date: 2020.12.11 13:48:24-03:00