MX2015003991A - Settable spacer fluids comprising pumicite and methods of using such fluids in subterranean formations. - Google Patents

Abstract

Methods and compositions for the treatment of subterranean formations, and more specifically, treatment fluids containing pumicite and methods of using these treatment fluids in subterranean formations, are provided. An example of a method is a method of displacing a fluid in a well bore. Another example of a method is a method of separating fluids in a well bore in a subterranean formation. An example of a composition is a settable spacer fluid comprising pumicite, an activating agent, and a base fluid.

Description

FLOWABLE SPACER FLUIDS THAT COMPRISE PUMICIT AND METHODS OF USE OF SUCH FLUIDS IN UNDERGROUND FORMATIONS CROSS REFERENCE TO RELATED REQUESTS This application is based on and claims the priority of United States Patent Application No. 13 / 630,507, entitled "Settable Spacer Fluids Comprising Pumice and Methods of Using Such Fluids in Subterranean Formations", filed on September 28, 2012, all the content of which are incorporated by reference in this document.

BACKGROUND OF THE INVENTION The present invention relates to underground treatment operations, and more particularly, to the improvement of treatment fluids comprising pumicite, and methods of using these improved treatment fluids, in underground formations.

Treatment fluids are used in a variety of operations that can be performed in underground formations. As referred to herein, the term "treatment fluid" is understood to mean any fluid that may be used in an underground application in conjunction with a desired function and / or for a desired purpose. The term "fluid of "treatment" does not involve any particular action by the fluid.The treatment fluids are often used in, for example, well drilling, termination and stimulation operations.Examples of such treatment fluids include, among other things, drilling fluids. , well cleaning fluids, reconditioning fluids, forming fluids, gravel packing fluids, acidification fluids, fracturing fluids, spacer fluids, and the like.

Spacer fluids are often used in oil and gas wells to facilitate the improvement of displacement efficiency when multiple fluids are displaced in a wellbore. For example, spacer fluids can often be placed within an underground formation in order to physically separate incompatible fluids. The spacer fluids can also be placed between the different drilling fluids during drilling fluid exchanges, or between a drilling fluid and a finishing brine.

The spacer fluids may also be used in primary or corrective cementing operations to separate, among other things, a drilling fluid from a cement composition that may be placed in an annular space between a coating string and the underground formation, or in the sounding, or within a coating string, if the cement composition is placed in the annular space either in the conventional direction or in reverse circulation. The cement composition is often intended, inter alia, to fit into the annular space, supporting and positioning the coating string, and bonding both to the coating string and forming to form a substantially impermeable barrier, or coating of cement, which facilitates zonal isolation. The cement composition can also be set inside the string or inside the borehole. If the spacer fluid does not adequately displace the drilling fluid from the ring, or the grout does not adequately displace the circular crown spacer, the cement composition may fail to attach to the cover string and / or the formation in the desired size, or drilling fluid gaps and / or spacer fluid may be left, which could compromise the hydraulic insulation. Under certain circumstances, the spacer fluids may also be placed in underground formations to ensure that all downhole surfaces are moistened prior to the subsequent placement of a cementitious composition, which may improve the bonding that occurs.

It produces between the cement composition and the wetted surfaces.

Conventional treatment fluids, including spacer fluids, often comprise materials that are expensive and which, in certain circumstances, may be unstable at elevated temperatures. This is problematic, among other things, because it can increase the cost of underground operations involving the treatment fluid.

Treatment fluids comprising vitrified slate may contain crystalline silica. For example, the vitrified slate may contain around 16% crystalline and amorphous silica. Inhalation of crystalline silica is a risk and can lead to health problems, such as silicosis, with prolonged exposure.

DETAILED DESCRIPTION OF THE INVENTION The present invention relates to underground treatment operations, and more particularly, to the improvement of treatment fluids comprising pumicite, and methods of using these improved treatment fluids in underground formations. The treatment fluids of the present invention are suitable for use in a variety of underground treatment applications, including Well drilling, cementing, termination, and stimulation operations.

In one embodiment, the present disclosure provides a settable spacer fluid comprising pumicite, an activating agent, and a base fluid.

In another embodiment, the present invention provides a method of using a settable fluid in a well bore, comprising: providing a well bore having a first fluid disposed therein; placing a second fluid in the well to displace at least a portion of the first fluid thereof, wherein the second fluid comprises pumicite, an activating agent, and a base fluid; and allowing the second fluid to at least partially set in the wellbore.

In another embodiment, the present invention provides a method of moving a fluid in a well bore, comprising: providing a well bore having a first fluid disposed therein; placing a second fluid in the well to displace at least a portion of the first fluid therefrom, wherein the second fluid comprises pumicite, an activating agent, and a base fluid; the placement of a cement composition in the drill hole to displace at least a first part of the second fluid thereof, wherein at least one second portion of the first fluid remains therein; allowing the cement composition to at least partially set in the wellbore; and allowing the second portion of the second fluid to at least partially set in the wellbore.

The features and advantages of the present invention will be readily apparent to those skilled in the art upon reading the description of the preferred embodiments which follows.

The treatment fluids of the present invention generally comprise pumicite and a base fluid. Optionally, the treatment fluids of the present invention may comprise additional additives that may be necessary or beneficial for a particular use. For example, the treatment fluids of the present invention can include other additives such as viscosity enhancing agents, organic polymers, dispersants, surfactants, weighting agents, vitrified shale, and any combination thereof.

The pumice used in the treatment fluids of the present invention generally comprises any volcanic or similar material filled with cavities and very light in weight. The term "pumicite" as used here, refers to a volcanic rock, like solidified foamy lava. In some embodiments of the present invention, the pumicite can be an amorphous aluminum silicate, containing less vitreous shale crystalline silica. In certain embodiments, pumicite may contain less than 1% crystalline silica. In certain embodiments of the present invention, the pumice is sized to pass through a 200 mesh screen (DS-200). Pumicite may be cheaper and / or safer than vitrified shale, and may be useful in environmentally sensitive regions.

In certain embodiments of the present invention, pumicite is present in the treatment fluids of the present invention in an amount in the range of about 0.01% to about 90% by weight of the treatment fluid. In other embodiments of the present invention, pumicite is present in the treatment fluids of the present invention in an amount in the range of about 1% to about 20% by weight of the treatment fluid. In other embodiments of the present invention, pumicite is present in the treatment fluids of the present invention in an amount in the range of about 10% to about 40% by weight of the treatment fluid. An expert in the art, with the benefit of this description, will recognize an adequate amount of pumicite for a particular application.

The base fluid used in the treatment fluids of the present invention may comprise an aqueous base fluid, an oil-based fluid, a synthetic fluid, or an emulsion. In certain embodiments of the present invention, the base fluid may be an aqueous base fluid comprising fresh water, salt water, brine, sea water, or a mixture thereof. In certain embodiments of the present invention, the base fluid may be an aqueous base fluid which may comprise cesium and / or potassium formate. The base fluid can be from any source, as long as it does not contain compounds that can adversely affect other components in the treatment fluid. The base fluid can be from a natural or synthetic source. In certain embodiments of the present invention, the base fluid may comprise a synthetic fluid, such as, but not limited to, esters, ethers, and olefins. Generally, the base fluid will be present in the treatment fluids of the present invention in an amount sufficient to form a pumpable suspension. In certain embodiments, the base fluid will be present in the treatment fluids of the present invention in an amount in the range of about 15% to about 95% by weight of the treatment fluid. In other embodiments, the base fluid will be present in the treatment fluids of the present invention in a amount in the range of about 25% to about 85% by weight of the treatment fluid. An ordinary expert in the art, with the benefit of this description, will recognize the appropriate amount of base fluid to be used for a chosen application.

Optionally, the treatment fluids of the present invention may further comprise a viscosity enhancing agent. The viscosity enhancing agent can be any suitable component to provide a desired degree of solids suspension. The choice of a viscosity enhancing agent depends on factors such as the desired viscosity and the desired chemical compatibility with other fluids (e.g., drilling fluids, cement compositions, and the like). In certain embodiments of the present invention, the viscosity enhancing agent can be easily flocculated and filtered out of the treatment fluids of the present invention. Suitable viscosity-increasing agents may include, but are not limited to, colloidal agents (e.g., clays, polymers, guar gum), emulsifying agents, diatomaceous earth, starches, biopolymers, synthetic polymers, or mixtures thereof. same. Suitable viscosity improving agents are often hydratable polymers having one or more functional groups. These Functional groups include, but are not limited to, hydroxyl groups, carboxyl groups, carboxylic acids, carboxylic acid derivatives, sulfate groups, sulfonate groups, phosphate groups, phosphonate groups, and amino groups. In certain embodiments of the present invention, the viscocity improving agents can be used to comprise hydroxyl groups and / or amino groups. In certain embodiments of the present invention, the agents that improve the viscosity can be biopolymers, and derivatives thereof, which have one or more of these monosaccharide units: galactose, mannose, glucoside, glucose, xylose, arabinose, fructose, glucuronic acid or pyranosyl sulfate. Examples of suitable biopolymers include, but are not limited to, guar gum and derivatives thereof, such as hydroxypropyl guar and carboxymethylhydroxypropyl guar, and cellulose derivatives, such as hydroxyethyl cellulose, welan gums, and xanthan gums. In addition, synthetic polymers containing the functional groups mentioned above can be used. Examples of such synthetic polymers include, but are not limited to, poly (acrylate), poly (methacrylate), poly (ethylene imine), poly (acrylamide), poly (vinyl alcohol), and poly (vinylpyrrolidone). Other suitable viscosity improving agents include chitosans, starches and gelatins. The right clays they include kaolinites, montmorillonite, bentonite, hydrated micas, attapulgite, sepiolite, and the like, as well as synthetic clays, such as laponite. An example of a suitable viscosity enhancing agent is a hydroxyethylcellulose which is commercially available under the tradename "WG-17" from Halliburton Energy Services, Inc., of Duncan, Oklahoma. Another example of a suitable viscosity enhancing agent is a welan gum which is commercially available under the tradename "BIOZAN" from Kelco Oilfield Services, Inc. Where it is included, the viscosity enhancing agent may be present in the treatment fluids. of the present invention in an amount sufficient to provide a desired degree of solids suspension. In certain embodiments, the viscosity enhancing agent may be present in an amount in the range of about 0.01% to about 35% by weight of the treatment fluid. In other embodiments, the viscosity enhancing agent may be present in an amount in the range of about 0.5% to about 2% by weight of the treatment fluid. In certain embodiments of the present invention wherein the treatment fluids will be exposed to elevated pH conditions (for example when contact was made with the treatment fluids with cement compositions), viscosity-increasing agents such as welan gum, cellulose (and cellulose derivatives), and xanthan gum may be particularly suitable. An ordinary expert in the art, with the benefit of this description, will be able to identify an appropriate viscosity enhancing agent, as well as the appropriate amount to include, for a particular application.

Optionally, the treatment fluids of the present invention may further comprise a fluid loss control additive. Any fluid loss control additive suitable for use in an underground application may be suitable for use in the compositions and methods of the present invention. In certain embodiments, the fluid loss control additive may comprise organic polymers, starches, or silica fines. An example of a silica fine that may be suitable is commercially available from Halliburton Energy Services, Inc. under the trade name "WAC-9". An example of a starch that may be suitable is commercially available from Halliburton Energy Services, Inc. under the trade name "DEXTRID." In certain embodiments where the treatment fluids of the present invention comprise a fluid loss control additive, the fluid loss control additive can to be present in the treatment fluids of the present invention in an amount in the range of about 0.01% to about 6% by weight of the treatment fluid. In other embodiments, the fluid loss control additive may be present in the treatment fluids of the present invention in an amount in the range of about 0.05% to about 1% by weight of the treatment fluid. A person skilled in the art, with the benefit of this disclosure, will recognize the appropriate amount of a fluid loss control additive to be used for a particular application.

Optionally, the treatment fluids of the present invention may comprise a dispersant. Suitable examples of dispersants include, but are not limited to, styrene sulfonated maleic anhydride copolymer, vinyl toluene sulfonated maleic anhydride copolymer, sodium naphthalene sulfonate condensed with formaldehyde, sulfonated acetone condensed with formaldehyde, lignosulfonates (e.g., sodium lignosulfonate) modified), allyloxybenzene sulfonate, allyl sulfonate and non-ionic monomers, and interpolymers of acrylic acid. An example of a dispersant that may be suitable is commercially available from National Starch & Chemical Company of Newark, New Jerscy under the trade name "Alcosperse 602 ND", and is a mixture of 6 parts of styrene-sulphonated maleic anhydride copolymer to 3.75 parts of acrylic acid interpolymer. Another example of a dispersant that may be suitable is a modified sodium lignosulfonate which is commercially available from Halliburton Energy Services, Inc., of Duncan, Oklahoma, under the tradename "HR®-5". Where the dispersant is included may be present in an amount in the range of about 0.0001% to about 4% by weight of the treatment fluid. In other forms of embodiment, the dispersant may be present in an amount in the range of about 0.0003% to about 1% by weight of the treatment fluid. A person skilled in the art, with the benefit of this disclosure, will recognize the appropriate amount of dispersant for inclusion in the treatment fluids of the present invention for a particular application.

Optionally, the treatment fluids of the present invention may comprise surfactants. Suitable examples of surfactants include, but are not limited to, nonylphenol ethoxylates, sugar alcohol ethoxylates, lipids, O-olefinsulfonates, alkyl polyglycosides, alcohol sulphates, ethoxylated alcohol sulfate salts, dimethylamine amidopropyl alkyl oxides, and oxides of dimethylamine amidopropyl alkene. An example of a surfactant that may be suitable comprises an oxyalkylated sulfonate, and is commercially available from Halliburton Energy Services, Inc. under the tradename "STABILIZER 434C". Another surfactant that may be suitable comprises an alkylpolysaccharide, and is commercially available from Seppic, Inc., of Fairfield, N.J. under the trade designation "SIMUSOL-10." Another surfactant that may be suitable comprises ethoxylated nonylphenols, and is commercially available under the trade name "DUAL SPACER SURFACTANT A" from Halliburton Energy Services, Inc. Wherever, the surfactant may be present in an amount in the range of about 0.01% to about 10% by weight of the treatment fluid. In other embodiments of the present invention, the surfactant may be present in an amount in the range of about 0.01% to about 6% by weight of the treatment fluid. An expert in the art, with the benefit of this description will recognize the appropriate amount of surfactant for a particular application.

Optionally, the treatment fluids of the present invention may comprise weighting agents. In general, any weighting agent can be used with the treatment fluids of the present invention.

Suitable weighting materials may include barium sulfate, hematite, manganese tetraoxide, ilmenite, calcium carbonate, and the like. An example of a suitable hematite is commercially available under the trade name "Hi-Dense® No.4" from Halliburton Energy Services, Inc. Where included, the filler may be present in the treatment fluid in an amount sufficient to provide a desired density for the treatment fluid. In certain embodiments, the bulking agent may be present in the treatment fluids of the present invention in the range of about 0.01% to about 85% by weight. In other embodiments, the bulking agent may be present in the treatment fluids of the present invention in the range of about 15% to about 70% by weight. An ordinary expert in the art, with the benefit of this description, will recognize the appropriate amount of weighting agent to use for a chosen application.

Optionally, other additives may be added to the treatment fluids of the present invention as deemed appropriate by one skilled in the art with the benefit of this disclosure. Examples of such additives include, among other things, defoamers, curing agents, salts, corrosion inhibitors, inhibitors of inlays, and the formation of conditioning agents. An ordinary expert in the art with the benefit of this disclosure will recognize the appropriate type of additive for a particular application.

Certain embodiments of the fluids of the present invention can demonstrate an improved "300/3" ratio. As contemplated herein, the term "300/3" ratio is understood to mean the value that results from dividing the shear stress that a fluid demonstrates at 300 rpm by the shear stress that the same fluid demonstrates at 3 ° C. rpm. When treatment fluids are used as spacer fluids, an ideal "300/3" ratio would be closely approximated to 1.0, indicating that the rheology of such fluid is flat. Flat rheology will facilitate, among other things, the maintenance of almost uniform fluid velocities through an underground ring, and can also result in an almost constant shear stress profile. In certain embodiments, flat rheology may reduce the volume of a spacer fluid that is required to effectively clean an underground well bore. Certain embodiments of the fluids of the present invention can demonstrate ranges 300/3 in the range of about 1 to about 9. In some modalities, the range can be about 2 to about 5. Certain embodiments of the fluids of the present invention can maintain an almost flat rheology over a wide range of temperatures.

The fluids of the present invention can be prepared in a variety of ways. In certain embodiments of the present invention, the well fluids of the present invention can be prepared by a first pre-mixing of the pumice with certain optional dry additives. The mixed dry materials can then be mixed with base fluid in the field, either by batch mixing or continuous mixing ("on the fly"). In certain embodiments of the present invention in which mixed dry materials are mixed with base fluid by batch mixing, a weak organic acid and defoamers are typically pre-mixed in the base fluid. The dry mix can then be added to the base fluid using, for example, an additive hopper with venturi effects; The mixture of the dry mixture and the base fluid can also be stirred, after which the weighting material can be added and stirred. The surfactants can be added to the spacer fluid shortly before they are placed at the bottom of the well. In certain embodiments of the present invention in which mixed dry materials are mixed With base fluid by continuous mixing, the mixed dry materials will typically be further mixed with a weighting material, and the resulting mixture can be measured in, for example, the recirculation cement mixing equipment while the base fluid is dosed by separated. The base fluid will typically comprise pre-mixed defoamers therein. Shortly before the spacer fluid is placed at the bottom of the well, the surfactants can be added to the spacer fluid. In other embodiments, the fluid can be prepared by mixing all but one or some of the components in a first location (e.g. in a suitable operating base) and then the remaining components can be added in a second location (such as the location of the well) before the fluid is pumped into the well.

An example of a method of the present invention is a method of moving a fluid in a well bore, comprising: providing a well bore having a first fluid disposed therein; and placing a second fluid in the well to at least partially displace the first fluid therefrom, wherein the second fluid comprises pumicite and a base fluid.

Another example of a method of the present invention is a method of separating fluids in a well bore in an underground formation, comprising: providing a well bore having a first fluid disposed therein; the placement of a spacer fluid in the well to separate the first fluid from a second fluid, the spacer fluid comprising pumicite and a base fluid; and the placement of a second fluid in the well.

An example of a composition of the present invention comprises 60.44% by weight of barite, 36.26% by weight of water, 3.08% by weight of pumicite and 0.22% by weight of Fe2. Another example of a composition of the present invention comprises 51.51% by weight of water, 42.67% by weight of barite, 5.65% by weight of pumicite and 0.17% by weight of Fe2. However, another example of a composition of the present invention comprises 75.93% by weight of water, 14.24% by weight of barite, 9.74% by weight of pumicite and 0.08% by weight of Fe2.

In certain embodiments, the present disclosure provides for settable spacer fluids. In other embodiments, the present disclosure provides for methods of formation of fraginable spacer fluids by the addition of an activating agent to the treatment fluids described herein. In other embodiments, the present disclosure provides methods of use of forgeable spacer fluids in underground formations.

The settable spacer fluids may generally comprise pumicite, a base fluid, and an activating agent. Optionally, the settable spacer fluids of the present invention may comprise additional additives that may be necessary or beneficial for a particular use. For example, the settable spacers of the present invention can include other additives such as accelerators, viscosity improving agents, organic polymers, dispersants, surfactants, weighting agents, vitreous slate, and any combination thereof.

The pumice used in the settable spacer fluids of the present invention generally comprises any volcanic or similar material filled with cavities and very light in weight. In some embodiments of the present invention, the pumicite present in the settable spacer fluids may be an amorphous aluminum silicate, containing less crystalline silica than vitrified slate. In certain embodiments, the pumicite present in the settable spacer fluids may contain less than 1% crystalline silica. In certain embodiments of the present invention, the pumicite present in the settable spacer fluids is sized to pass through a 200 mesh screen (DS-200). In other modalities, pumicite is dimensioned to pass through a mesh screen of 20 or 325.

In certain embodiments of the present invention, the pumicite may be present in the settable spacer fluids of the present invention in an amount in the range of about 0.01% to about 90% by weight of the settable spacer fluid. In other embodiments of the present invention, pumicite is present in the settable spacer fluids of the present invention in an amount in the range of about 1% to about 80% by weight of the settable spacer fluid. In other embodiments of the present invention, pumicyte is present in the settable spacer fluids of the present invention in an amount in the range of about 10% to about 60% by weight of the settable spacer fluid. In other embodiments of the present invention, pumicite is present in the settable spacer fluids of the present invention in an amount in the range of about 20% to about 40% by weight of the settable spacer fluid. In other embodiments of the present invention, pumicite is present in the settable spacer fluids of the present invention in an amount in the range of about 30% to about 35% by weight of the fluid settable spacer. An expert in the art, with the benefit of this description, will recognize an adequate amount of pumicite for a particular application.

The base fluid used in the fragrant spacer fluids of the present invention may comprise an aqueous base fluid, an oil-based fluid, a synthetic fluid, or an emulsion. In certain embodiments of the present invention, the base fluid may be an aqueous-based fluid comprising fresh water, salt water, brine, sea water, or a mixture thereof. In certain embodiments of the present invention, the base fluid may be an aqueous base fluid which may comprise cesium and / or potassium formate. The base fluid can be from any source, as long as it does not contain compounds that can adversely affect other components in the settable spacer fluid. The base fluid may be from a natural or synthetic source. In certain embodiments of the present invention, the base fluid may comprise a synthetic fluid, such as, but not limited to, esters, ethers, and olefins. Generally, the base fluid will be present in the settable spacer fluids of the present invention in an amount sufficient to form a pumpable suspension. In certain embodiments, the base fluid will be present in the settable spacer fluids of the present invention in an amount in the range of about 10% to about 95% by weight of the settable spacer fluid. In other embodiments, the base fluid will be present in the settable spacer fluids of the present invention in an amount in the range of about 25% to about 85% by weight of the settable spacer fluid. An ordinary expert in the art, with the benefit of this description, will recognize the appropriate amount of base fluid to be used for a chosen application.

In certain embodiments, the activating agent can be any material that allows the settable spacer fluids to fit in the well. In certain embodiments, the activating agent may be a material comprising a calcium source or a hydroxide source. In certain embodiments, the activating agent may comprise lime, calcium chloride, cement, calcium bromide, sodium hexametaphosphate, sodium silicate, or other sources of calcium. In certain embodiments, the activating agent may comprise hydrated lime.

In certain embodiments, the activating agent may be present in the settable spacer fluids of the present invention in an amount sufficient to allow for the settable spacer fluids to fit in the well. In certain modalities, the activation agent will be present in the settable spacer fluids of the present invention in an amount in the range of about 0.01% to about 35% by weight of the settable spacer fluid. In certain embodiments, the activating agent will be present in the settable spacer fluids of the present invention in an amount in the range of about 5% to about 10% by weight of the settable spacer fluid. In other embodiments, the mass ratio of the agent for pumicy activation can be from about 1:10 to about 1: 2. An ordinary expert in the art, with the benefit of this disclosure, will recognize the appropriate amount of activating agent at use for a chosen application.

Optionally, the settable spacer fluids of the present invention may further comprise a set accelerator. In general, any setting accelerator can be used with the settable spacer fluids of the present invention. One of ordinary skill in the art, with the benefit of this description, will be able to identify a set accelerator suitable for a particular application. Where used, the setting accelerator will generally be present in the settable spacer fluid in an amount in the range of about 0. 5% to about 8% by weight of the settable spacer fluid.

Optionally, the fragrant spacer fluids of the present invention may further comprise an agent that increases viscosity. The agent that increases the viscosity can be any suitable component to provide a desired degree of solids suspension. The choice of a viscosity enhancing agent depends on factors such as the desired viscosity and the desired chemical compatibility with other fluids (eg, drilling fluids, cement compositions, and the like). In certain embodiments of the present invention, the viscosity enhancing agent can be easily flocculated and filtered out of the settable spacer fluids of the present invention. Suitable viscosity assistants may include, but are not limited to, colloidal agents (eg, clays, polymers, guar gum), emulsion forming agents, diatomaceous earth, starches, biopolymers, synthetic polymers, or mixtures of the same. Suitable viscosity-increasing agents are often hydratable polymers having one or more functional groups. These functional groups include, but are not limited to, hydroxyl groups, carboxyl groups, carboxylic acids, carboxylic acid derivatives, groups sulfate, sulfonate groups, phosphate groups, phosphonate groups, and amino groups. In certain embodiments of the present invention, the viscosity enhancing agents may be used to comprise hydroxyl groups and / or amino groups. In certain embodiments of the present invention, the viscosity enhancing agents may be biopolymers, and derivatives thereof, having one or more of these monosaccharide units: galactose, mannose, glucoside, glucose, xylose, arabinose, fructose, acid glucuronic or pyranosyl sulfate. Examples of suitable biopolymers include, but are not limited to, guar gum and derivatives thereof, such as hydroxypropyl guar and carboxymethylhydroxypropyl guar, and cellulose derivatives, such as hydroxyethyl cellulose, welan gums, and xanthan gums. In addition, synthetic polymers containing the functional groups mentioned above can be used. Examples of such synthetic polymers include, but are not limited to, poly (acrylate), poly (methacrylate), poly (ethylene imine), poly (acrylamide), poly (vinyl alcohol), and poly (vinylpyrrolidone). Other suitable viscosity enhancing agents include chitosans, starches and gelatins. Suitable clays include kaolinites, montmorillonite, bentonite, hydrated micas, attapulgite, sepiolite, and the like, as well as synthetic clays, such as laponite. An example of a suitable viscosity enhancing agent is a hydroxyethylcellulose which is available coercially under the tradename "WG-17" from Halliburton Energy Services, Inc., of Duncan, Oklahoma. Another example of a suitable viscosity enhancing agent is a welan gum which is commercially available under the tradename "BIOZAN" from Kelco Oilfield Services, Inc. Where it is included, the viscosity enhancing agent may be present in the settable spacer fluids. of the present invention in an amount sufficient to provide a desired degree of solids suspension. In certain embodiments, the viscosity enhancing agent may be present in an amount in the range of about 0.01% to about 35% by weight of the settable spacer fluid. In other embodiments, the viscosity enhancing agent may be present in an amount in the range of about 0.5% to about 2% by weight of the settable spacer fluid. In certain embodiments of the present invention wherein the treatment fluids will be exposed to high pH conditions (eg, when the treatment fluids are contacted with cement compositions), viscosity increasing agents such as welan gum, cellulose (and derivatives of cellulose), and xanthan gum can be particularly suitable. An ordinary expert in the art, with the benefit of this description, will be able to identify an appropriate viscosity enhancing agent, as well as the appropriate amount to include, for a particular application.

Optionally, the settable spacer fluids of the present invention may further comprise a fluid loss control additive. Any fluid loss control additive suitable for use in an underground application may be suitable for use in the compositions and methods of the present invention. In certain embodiments, the fluid loss control additive may comprise organic polymers, starches, or silica. An example of a silica fine that may be appropriate is commercially available from Halliburton Energy Services, Inc. under the trade name "WAC-9". An example of a starch that may be suitable is commercially available from Halliburton Energy Services, Inc. under the tradename "N-Dril HT Plus". In certain embodiments in which the settable spacer fluids of the present invention comprise a fluid loss control additive, the fluid loss control additive may be present in the settable spacer fluids of the present invention in an amount in the range approximately 0. 01% to about 6% by weight of active ingredient. In other embodiments, the fluid loss control additive may be present in the settable spacer fluids of the present invention in an amount in the range of about 0.05% to about 2% by weight of active ingredient. A person skilled in the art, with the benefit of this disclosure, will recognize the appropriate amount of a fluid loss control additive to be used for a particular application.

Optionally, the settable spacer fluids of the present invention may comprise a dispersant. Suitable examples of dispersants include, but are not limited to, styrene sulfonated maleic anhydride copolymer, vinyl toluene sulfonated maleic anhydride copolymer, sodium naphthalene sulfonate condensed with formaldehyde, sulfonated acetone condensed with formaldehyde, lignosulfonates, lignosulfonates (e.g., lignosulfonate sodium modified), allyloxybenzene sulfonate, allyl sulfonate and nonionic monomers, and interpolymers of acrylic acid. An example of a dispersant that may be suitable is commercially available from National Starch & Chemical Company of Newark, New Jerscy under the trade name "Alcosperse 602 ND", and is a mixture of 6 parts of styrene-sulfonated maleic anhydride copolymer at 3.75 Interpolymer parts of acrylic acid. Another example of a dispersant that may be suitable is a modified sodium lignosulfonate which is commercially available from Halliburton Energy Services, Inc., of Duncan, Oklahoma, under the tradename "CFR-3". Where included, the dispersant may be present in an amount in the range of about 0.0001% to about 4% by weight of active ingredient. In other forms of embodiment, the dispersant may be present in an amount in the range of about 0.0003% to about 1% by weight of active ingredient. A person skilled in the art, with the benefit of this disclosure, will recognize the appropriate amount of dispersant for inclusion in the treatment fluids of the present invention for a particular application.

Optionally, the settable spacer fluids of the present invention may comprise surfactants. Examples of suitable surfactants include, but are not limited to, nonylphenol ethoxylates, alcohol ethoxylates, sugar lipids, α-olefin sulphonates, alkyl polyglycosides, alcohol sulfates, ethoxylated alcohol sulfate salts, dimethylamine amidopropyl alkyl oxides, and oxides of dimethylamine amidopropyl alkene. An example of a surfactant that may be suitable comprises an oxyalkylated sulfonate, and is commercially available from Halliburton Energy Services, Inc. under the trade name "SEM-8". Another surfactant that may be suitable comprises an alkyl polysaccharide, and is commercially available from Seppic, Inc. of Fairfield, N.J. under the trade name "SIMUSOL-IO". Another surfactant that may be suitable comprises ethoxylated nonylphenols, and is commercially available under the tradename "DUAL SPACER SURFACTANT A" from Halliburton Energy Services, Inc. Where included, the surfactant may be present in an amount in the range of about 0.01. % to about 10% by weight of the settable spacer fluid. In other embodiments of the present invention, the surfactant may be present in an amount in the range of about 0.01% to about 6% by weight of the settable spacer fluid. An expert in the art, with the benefit of this description will recognize the appropriate amount of surfactant for a particular application.

Optionally, the settable spacer fluids of the present invention may comprise weighting agents.

In general, any weighting agent can be used with the settable spacer fluids of the present invention. Suitable weighting materials may include barite, hematite, manganese tetraoxide, ilmenite, calcium carbonate, crushed stone, silica, cement kiln dust, silica, and the like. An example of a suitable hematite is commercially available under the trade name "Hi-Dense® No. 4" from Halliburton Energy Services, Inc. Where included, the weighting agent may be present in the settable spacer fluid in an amount sufficient to provide a desired density to the settable spacer fluid. In certain embodiments, the bulking agent may be present in the settable spacer fluids of the present invention in the range of about 0.01% to about 85% by weight. In other embodiments, the bulking agent may be present in the settable spacer fluids of the present invention in the range of about 15% to about 70% by weight. An ordinary expert in the art, with the benefit of this description, will recognize the appropriate amount of weighting agent to use for a chosen application.

Optionally, other additives may be added to the settable spacer fluids of the present invention as deemed appropriate by one skilled in the art with the benefit of this disclosure. Examples of such additives include, among other things, strength restoration additives, circulation loss materials, additives. weight reduction, friction reduction materials, defoamers, curing agents, salts, corrosion inhibitors, scale inhibitors, and the formation of conditioning agents. An ordinary expert in the art with the benefit of this disclosure will recognize the appropriate type of additive for a particular application.

Certain embodiments of the settable spacer fluids of the present invention can demonstrate improved "300/3" ratios, as defined in the paragraph above. In certain embodiments, the "300/3" ratio for the settable spacer fluids discussed herein may be in the range of about 1 to about 50. In some embodiments, the range may be from about 5 to about 20. In others modalities, the range can be from about 10 to about 15.

The settable spacer fluids of the present invention can be prepared in a variety of ways. In certain embodiments of the present invention, the settable spacer fluids of the present invention may be first prepared by pre-mixing the pumice with certain optional dry additives. Then, mixed dry materials can be mixed with base fluid in the field, either by batch mixing or continuous mixing ("on In certain embodiments of the present invention where mixed dry materials are mixed with base fluid by batch mixing, a weak organic acid and defoamers are typically pre-mixed in the base fluid.The dry mixture can then be added To the base fluid using, for example, an additive hopper with venturi effects, the mixture of the dry mix and the base fluid can also be agitated, after which the weighting material can be added and stirred in. Surfactants can be added to the spacer fluid shortly before they are placed at the bottom of the well In certain embodiments of the present invention in which mixed dry materials are mixed with base fluid by continuous mixing, the dry mixed materials can typically be mixed later with a weighting material, and the resulting mixture can be measured in, for example, recirculating cement mixing equipment while after the base fluid is dosed separately. The base fluid will typically comprise pre-mixed defoamers therein. Shortly before the settable spacer fluid is placed into the orifice, the surfactants can be added to the spacer fluid. In other embodiments, the fluid may be prepared by mixing all but one or some of the components in a first location (eg, in a base). of suitable operations) and then the remaining components (such as the activation agent) can be added in a second location (such as the location of the well) before the fluid is pumped into the well.

In another embodiment, a settable spacer fluid can be prepared by adding the activating agent and / or pumicite to an existing well drilling fluid. In certain embodiments, the activating agent and / or pumicite may be added to the existing wellbore drilling fluid while it is present in the well bore or after it has been removed from the wellbore. For example, in certain embodiments a settable spacer fluid can be prepared by the addition of an activating agent and / or pumicite to a drilling fluid present in the wellbore after performing a drilling operation. In other forms of embodiment, a settable spacer fluid can be prepared by the addition of an activating agent and / or pumicite to a drilling fluid that has been removed from the wellbore after performing a drilling operation. In certain embodiments, the drilling fluid may comprise pumicite.

An example of a method of the present invention is a method of moving a fluid in a perforation of well, comprising: providing a well bore having a first fluid disposed therein; placing a second fluid in the well bore to at least partially displace the first fluid thereof, wherein the second fluid comprises pumicite, a base fluid, and an activating agent; and allow the second fluid to set in the hole in the well.

Another example of a method of the present invention is a method of separating fluids in a well bore in an underground formation, comprising: providing a well bore having a first fluid disposed therein; placing a second fluid in the well to displace at least a portion of the first fluid thereof, wherein the second fluid comprises pumicite, an activating agent, and a base fluid; and allowing the second fluid to at least partially set in the wellbore.

Another example of a method of the present invention is a method of separating fluids in a well bore in an underground formation, comprising: providing a well bore having a first fluid disposed therein; placing a second fluid in the well to displace at least a portion of the first fluid thereof, wherein the second fluid comprises pumicite, an agent of activation, and a base fluid; placing a cement composition in the drill hole to displace at least a first part of the second fluid therefrom, wherein at least a second portion of the first fluid remains therein; allowing the cement composition to at least partially cure in the hole of the well; and allowing the second portion of the second fluid to at least partially set in the wellbore.

To facilitate a better understanding of the present invention, the following examples of preferred embodiments are given. In no way should the following examples be read to limit or define the scope of the invention. EXAMPLES Example 1. A rheological test was carried out in a variety of exemplary compositions that were prepared as follows. First, all dry components (e.g., pumiceite, or vitrified slate, or zeolite or fumed silica, in addition to the dry additives, such as, for example, hydroxyethylcellulose, BIOZAN, citric acid, barite, and sodium lignosulfonate ) were weighed in a glass container having a clean lid and completely shaken by hand until well mixed. Weighed tap water in a blender, and the blender was turned on 3000-4000 rpm. While the mixer was still spinning, it they added the mixed dry components together with 2 drops of a glycol-based antifoam standard. The speed of the blender was maintained at 3,000-4,000 rp for approximately 5 minutes.

The rheological values were determined using a Chan model 35 viscometer. The readings were recorded at a speed of 3, 6, 30, 60, 100, 200, and 300 RPM with a Bl shake, a Rl rotor, and a 1.0 spring.

Composition Sample No. 1 comprised a suspension of 16 pounds per gallon of shale, 29.6 grams of Tuned Spacer III blend ("TS III") 580.9 grams of barite, 348.5 grams of water, and 2.13 grams of Fe2.

Composition Sample No.2 replaced the slate with pumicite DS-200, and comprised a suspension of 16 pounds per gallon of Pumicite DS-200, 29.6 grams of TS III blend, 580.9 grams of barite, 348.5 grams of water, and 2.13 grams Fe2.

Composition Sample No. 3 comprised a suspension of 13 pounds per gallon of shale, 44.1 grams of TS III mixture, 333.2 grams of barite, 402.2 grams of water, and 1.32 grams of Fe2.

Composition Sample No.4 replaced the shale with pumicite DS-200, and comprised a suspension of 13 pounds per gallon of pumicite DS-200, 44.1 grams of TS III blend, 333. 2 grams of barite, 402.2 grams of water, and 1.32 grams Fe2 · Composition Sample No. 5 comprised a suspension of 10 pounds per gallon of shale, 58.5 grams of TS III blend, 85.5 grams of barite, 455.9 grams of water, and 0.5 grams of Fe2.

Composition Sample No. 6 replaced the slate with pumicite DS-200, and comprised a suspension of 10 pounds per gallon of Pumicite DS-200, 58.5 grams of TS III blend, 85.5 grams of barite, 455.9 grams of water, and 0.5 grams Fe2.

The test results are set forth in Table 1 below. The abbreviation "PV" means plastic viscosity, while the abbreviation "gr" refers to the limit of elasticity. okay) IP or Ü1 O NJ U1 or in A series of different tests were performed on a variety of sample compositions that were prepared as follows. First, all dry components (eg, pumice and lime, in addition to dry additives) were weighed in a glass container having a clean lid, and thoroughly shaken by hand until they were thoroughly mixed. The liquid additives were measured in suitable syringes. Tap water was weighed in a blender, and the blender was turned on at 3000-4000 rpm. While the blender was still on, the mixed dry and liquid components were added along with 2 drops of a glycol-based antifoam standard. The speed of the blender was maintained at 3000-4000 rpm for approximately 5 minutes. This mixing sequence was repeated the number of times it was necessary to take the test.

The rheological values were determined using a Chan model 35 viscometer. The readings were recorded at a speed of 3, 6, 30, 60, 100, 200, and 300 RPM with a Bl shake, a Rl rotor, and a 1.0 spring.

A composition of the sample comprised 600 kg / m3 of pumicite, 504.6 L / m3 of water, 367.95 kg / m3 of barite, 50 L / m3 of fluid loss control agent, 100 kg / m3 of KC1, 167 kg / m3 of lime, 3 L / m3 of antifoam, and 24 L / m3 of surfactant. The thickening time measured for this composition was 48 hours and 47 minutes at 47.7 ° C (118 ° F). The thickening time measured for the composition was then determined to be 20 hours and 2 minutes at 93.3 ° C (200 ° F). The composition was tested for strength development using an ultrasonic cement analyzer. A value of 36.77 kg / cm2 (523 psi) was measured at 48 hours. After a 7 day cure, some mechanical properties were measured by the use of a destructive test method. The composition had a tensile strength of 14.62 kg / cm2 (208 psi), a Young's modulus of 29037.64 kg / cm2 (413000 psi), a Poisson's ratio of 0.179, and a compressive strength of 76.70 kg / cm2 (1091 psi).

The results of the rheology tests for the composition of the sample at 680 F and 118 0 F in units of centipoises are set forth in Table 2 below.

TABLE 2 The above examples demonstrate, among other things, that the improvement of the treatment fluids of the present invention comprising puffite and a base fluid may be suitable for use in the treatment of underground formations. An expert in the technique will appreciate that the vitrified slate can be used in conjunction with the pumice described in this document.

Therefore, the present invention is well adapted to achieve the ends and advantages mentioned, as well as those that are inherent to it. The particular embodiments described above are illustrative only, since the present invention can be modified and practiced in different but equivalent ways apparent to those skilled in the art having the benefit of the teachings herein. In addition, no limitation is intended to the details of construction or design shown herein, except as described in the following claims. Therefore, it is evident that the particular illustrative modalities described above may be altered or modified and all these variations are considered within the scope and spirit of the present invention. Although the compositions and methods are described in terms of "comprising", "containing", or "including" various components or steps, the compositions and methods may also "consist essentially of" or "composed of" the various components and steps . All numbers and ranges described above may vary by a certain amount. Each time a numerical range with a lower limit and upper limit is described, any number and any included range fall within the range that is specifically described. In particular, each range of values (of the form, "from about A to about B", or, equivalently, "from about A to B", or, equivalently, "from about ab") described in this document should be understood to mean that It is established to each number and range encompassed within the broadest range of values. In addition, the terms of the claims have their plainness, ordinary meaning unless explicitly and clearly defined by the patentee.

On the other hand, the indefinite articles "a" or "an", as used in the claims, are defined in this document to mean one or more of one of the elements that it introduces. If there is any conflict in the uses of a word or term in this description and one or more patents or other documents that may be incorporated herein by reference, definitions that are consistent with this specification must be approved.

Claims (20)

NOVELTY OF THE INVENTION Having described the present invention, it is considered as a novelty and, therefore, the content of the following is claimed as property: CLAIMS

1. A settable spacer fluid comprising pumicite, an activating agent, and a base fluid.

2. The settable spacer fluid according to claim 1, wherein the activating agent comprises at least one activating agent selected from the group consisting of: lime; calcium chloride; calcium bromide; sodium hexametaphosphate; sodium silicate; sodium sulfate; and a combination of them.

3. The settable spacer fluid according to claim 1, characterized in that it also comprises a setting accelerator.

4. The settable spacer fluid according to claim 1, wherein the pumicite is present in an amount from about 0.01% to about 90% by weight of the settable spacer fluid.

5. The settable spacer fluid according to claim 1 wherein the activating agent is present in an amount from about 0.01% to about 35% by weight of the settable spacer fluid.

6. The settable spacer fluid according to claim 1, wherein the base fluid comprises at least one of the following: an aqueous base fluid, an emulsion, a synthetic fluid, or an oil-based fluid.

7. The settable spacer fluid according to claim 1, wherein the ratio 300/3 of the settable spacer fluid is from about 5 to about 50.

8. A method of using a settable fluid in a well bore, characterized in that it comprises: i. providing a well bore having a first fluid disposed therein; ii. placing a second fluid in the well bore to displace at least a portion of the first fluid thereof, wherein the second fluid comprises pumicite, an activating agent, and a base fluid; Y iii. allowing the second fluid to at least partially set in the wellbore.

9. The method according to claim 8, wherein the activating agent comprises at least one activating agent selected from the group consisting of: lime; calcium chloride; calcium bromide; hexametaphosphate sodium; sodium silicate; sodium sulfate; and a combination of them.

10. The method according to claim 8, wherein the second fluid further comprises a setting accelerator.

11. The method according to claim 8, wherein the pumicite is present in the second fluid in an amount from about 0.01% to about 90% by weight of the second fluid.

12. The method according to claim 8, wherein the activating agent is present in the second fluid in an amount from about 0.01% to about 35% by weight of the second fluid.

13. The method according to claim 8, wherein the base fluid comprises at least one of the following: an aqueous base fluid, an emulsion, a synthetic fluid, or an oil-based fluid.

14. The method according to claim 8, wherein the ratio 300/3 of the second fluid is from about 5 to about 50.

15. The method according to claim 8, characterized in that it further comprises preparing the second fluid, wherein the second fluid is prepared by adding the activating agent to a drilling fluid.

16. A method of using a settable fluid in a well borehole, comprising: i. providing a well bore having a first fluid disposed therein; ii. placing a second fluid in the well bore to displace at least a portion of the first fluid therefrom, wherein the second fluid comprises puff, an activating agent, and a base fluid; iii. placing a cement composition in the well bore to displace at least a first portion of the second fluid thereof, wherein at least a second portion of the first fluid remains therein; iv. allowing the cement composition to at least partially set in the wellbore; Y v. allowing the second portion of the second fluid to at least partially set in the well bore.

17. The method according to claim 16, further comprising placing a coating string into the well bore, wherein the coating string is placed into the well bore after placing the second fluid in the borehole. and before placing the cement composition in the well.

18. The method according to claim 16, wherein the activating agent comprises at least one activating agent selected from the group consisting of: lime; calcium chloride; calcium bromide; sodium hexametaphosphate; sodium silicate; sodium sulfate; and a combination of them.

19. The method according to claim 16, wherein the second fluid further comprises an accelerator of the faguado.

20. The method according to claim 16, wherein the first fluid comprises a drilling fluid.