Patent Application
20240425742
During the drilling and completion of oil and gas wells, various wellbore treatments are performed on the wells for a number of purposes. For example, a wellbore is typically drilled down to the subterranean formation while circulating a drilling fluid through the wellbore. After the drilling is terminated, a string of pipe, e.g., casing, is run in the wellbore. Primary cementing is then usually performed whereby a cementing fluid, usually including water, cement, and particulate additives, is pumped down through the string of pipe and into the annulus between the string of pipe and the walls of the wellbore to allow the cementing fluid to set into an impermeable cement column and thereby seal the annulus. Subsequent secondary cementing operations, i.e., any cementing operation after the primary cementing operation, may also be performed. One example of a secondary cementing operation is squeeze cementing whereby a cementing fluid is forced under pressure to areas of lost integrity in the annulus to seal off those areas.
A variety of fluids are used in both drilling and completing the wellbore and in resource recovery. Example fluids include drilling fluid, also called mud, that is pumped into the wellbore during drilling and similar operations, spacer, which helps flush residual drilling fluid from the wellbore, cement, which typically lines at least part of the finished wellbore and is placed after flushing with a spacer, and fracturing fluids, which may be used to enhance oil or natural gas recovery. Although some parts of the wellbore lie near the surface, the majority of it is deep underground, where harsh conditions are found. In addition, any problems with a downhole fluid can be difficult to detect or correct because the fluid may be far away from the surface and relatively inaccessible, particularly in the case of cement that has set and is no longer a fluid.
As the bottom hole circulating temperature of a well increases, the viscosity of a cementing fluid decreases. This decrease in viscosity, which is known as thermal thinning, can result in settling of the solids in the slurry. Undesirable consequences of the solids settling include free water and a density gradient in the set cement. To inhibit settling, cement suspending agents, e.g., crosslinked polymers, can be added to the cementing fluid. As the cementing fluid temperature increases, the cement suspending agent is thought to maintain or increase the viscosity of the cementing fluid, for example, by breaking at least part of the crosslinks to ensure that the polymer remains extended to provide stable viscosity. One important feature of a cement suspending agent is that it does not adversely affect low-temperature rheology. Existing cement suspending additives, e.g., guar or guar derivatives crosslinked with borate, delay crosslink breakage sufficiently to allow mixing and pumping of a cement fluid without imparting an excessively high viscosity. However, those existing suspension additives are known to degrade above 280° F. This temperature limitation makes these cement suspension additives impractical for use in higher temperature applications.
These drawings illustrate certain aspects of some of the embodiments of the present disclosure and should not be used to limit or define the disclosure.
The present disclosure is directed to wellbore treatment fluids comprising a high temperature suspension additive. More particularly, the high temperature suspension additive may be included in wellbore treatment fluids such as in spacer fluids and cement slurries where thermal thinning may occur. The high temperature suspension additive may be advantageous in that it provides suspension of solids in subterranean formations that have bottom hole static temperatures (BHST) of 280° F. (138° C.) or greater, including those formations that have a bottom hole static temperature in excess of about 400° F. (204° C.). The high temperature suspension additives of the present disclosure are operable at significantly higher temperatures than conventional biopolymer-based suspension additives such as guar gum and xanthan gum. The high temperature suspension additives of the present disclosure are further advantageous over biopolymer-based suspension additives as the high temperature suspension additives do not adversely affect the low-temperature viscosity of a treatment fluid and allow for low temperature mixability as well as high temperature suspension.
In embodiments, the high temperature suspension additive comprises a reaction product of a monomer, a thermally unstable crosslinker and a thermally stable crosslinker. Examples of the monomers may include, but are not limited to, one or more monomers selected from the group comprising acrylamide (Ac), methacrylamide, 2-acrylamido-2-methyl-1-propanesulfonic acid and salts thereof, N-vinylpyrrolidone (NVP), N-substituted acrylamides, N-substituted methacrylamides, N-methylacrylamide, N-ethylacrylamide, N-vinylcaprolactam, N,N-dimethylacrylamide, N,N-dimethylmethacrylamide, acrylic acid, methacrylic acid, acrylates (such as methyl acrylate and hydroxyethyl acrylate), methacrylates (such as methyl methacrylate, 2-hydroxyethyl methacrylate, and 2-dimethylaminoethyl methacrylate), and combinations thereof.
The thermally unstable crosslinkers for use in the present disclosure may be a crosslinker with at least two acrylamide, methacrylamide, acrylate, methacrylate, vinyl or vinylidene ester, allyl ester groups, or combinations that is hydrolytically stable at ambient temperature and hydrolytically unstable at high temperature, i.e., above 250° F. (121° C.), on the timescale of the well treatment, such as a period of time of one hour or longer. As used herein, “hydrolytically stable,” and any derivative thereof, indicates stable against hydrolysis at a selected temperature for a selected period of time. A suitable thermally unstable crosslinker may hydrolyze at temperature at a point in a range from 250° F. (121° C.) to 550° C. (288° C.). Alternatively, at a point in a range of 250° F. (121° C.) to 350° F. (177° C.), 350° F. (177° C.) to 400° F. (204° C.), 400° F. (204° C.) to 500° F. (260° C.), 500° F. (260° C.) to 550° F. (288° C.), or any ranges therebetween.
The thermally unstable crosslinkers used in the methods and compositions of the present disclosure generally comprise one or more of the following crosslinkers: acrylamide-based crosslinkers, acrylate-based crosslinkers, ester-based crosslinkers, amide-based crosslinkers, any derivatives thereof, and any combinations thereof. These crosslinkers are stable at ambient temperatures, but will hydrolyze at higher temperatures and, as a result, causes the breaking of the crosslinking. In certain embodiments, the acrylamide-based crosslinkers may be monomers with at least one acrylamide or methacrylamide group, which may also contain additional unsaturated groups such as vinyl, allyl, and/or acetylenic groups. In certain embodiments, the acrylate-based crosslinkers may be monomers with at least one acrylate or methacrylate group, which may also contain additional unsaturated groups such as vinyl, allyl, and/or acetylenic groups.
Examples of acrylamide-based crosslinkers that may be suitable in certain embodiments of the present disclosure include, but are not limited to, N,N′-methylenebisacrylamide, N,N′-methylenebismethacrylamide, N,N′-ethylenebisacrylamide, N,N′-propylenebisacrylamide, and higher order derivatives, N,N′-(1,2-dihydroxyethylene)bisacrylamide, 1,4-diacryloylpiperazine, N,N-diallylacrylamide, and 1,3,5-triacryloylhexahydro-1,3,5-triazine.
Examples of acrylate-based crosslinkers that may be suitable in certain embodiments of the present disclosure include, but are not limited to, ethylene glycol di(meth) acrylate, propylene glycol di(meth) acrylate, diethylene glycol di(meth) acrylate, triethylene glycol di(meth) acrylate, polyethylene glycol di(meth) acrylate, 1,4-butanediol di(meth) acrylate, 1,6-hexanediol di(meth) acrylate, 1,1,1-trimethylolpropane trimethacrylate, pentaerythritol tri(meth) acrylate, pentaerythritol tetra(meth) acrylate, glycerol di(meth) acrylate, glycerol tri(meth) acrylate, triglycerol di(meth) acrylate, allyl(meth) acrylate, vinyl(meth) acrylate, tris [2-(acryloyloxy)ethyl] isocyanurate.
Examples of ester-based and amide-based crosslinkers that may be suitable in certain embodiments of the present disclosure include, but are not limited to, vinyl or allyl esters, such as diallyl carbonate, divinyl adipate, divinyl sebacate, N,N′-diallyltartardiamide, diallyl phthalate, diallyl maleate, and diallyl succinate.
In some embodiments, the thermally stable crosslinkers may be a crosslinker with at least two vinyl, vinylidene, or allyl groups, or combinations thereof that is hydrolytically stable in the wellbore treatment fluid under higher temperatures such as above 250° F. (121° C.) to about 450° F. (232° C.), on the timescale of the well treatment, such as a period of time of one hour or longer. For example, the thermally stable crosslinkers may not hydrolyze or only partially hydrolyze where less than about 10% of the crosslinks hydrolyze in a treatment fluid at a temperature in a range of 250° F. (93° C.) to 450° F. (232° C.) for a period of at least about 1 hour. Alternatively, in a range of 200° F. (93° C.) to 300° F. (149° C.), 300° F. (149° C.) to 400° F. (204° C.), 400° F. (204° C.) to 450° F. (232° C.), or any ranges therebetween.
The thermally stable crosslinkers are typically ether-based and not amide- or ester-based. Unlike the amide- and ester-based crosslinkers, these crosslinkers are more resistant to thermal hydrolysis or even do not hydrolyze at high temperatures. Nonlimiting examples of thermally stable crosslinkers may include divinyl ether, diallyl ether, vinyl or allyl ethers of polyglycols or polyols (such as pentaerythritol allyl ether (PAE), allyl sucrose, ethylene glycol divinyl ether, triethylene glycol divinyl ether, diethylene glycol divinyl ether, glycerol diallyl ether, and polyethylene glycol divinyl ether, propylene glycol divinyl ether, and trimethylolpropane diallyl ether), divinylbenzene, 1,3-divinylimidazolidin-2-one (also known as 1,3-divinylethyleneurea or divinylimidazolidone), divinyltetrahydropyrimidin-2 (1H)-one, dienes (such as 1,7-octadiene and 1,9-decadiene), allyl amines (such as triallylamine and tetraallylethylene diamine), N-vinyl-3 (E)-ethylidene pyrrolidone, ethylidene bis(N-vinylpyrrolidone), triallyl isocyanurate (TTT), and any combination of any of the foregoing.
The high temperature suspension additive may have a polymer entanglement concentration (P*) in a range of 0.001 g/dL to 0.1 g/dL. Alternatively, in a range of 0.001 g/dL to 0.005 g/dL, 0.005 g/dL to 0.01 g/dL, 0.01 g/dL to 0.05 g/dL, 0.05 g/dL, to 0.1 g/dL, or any ranges therebetween.
The one or more monomers may be present in the high temperature suspension additive in an amount ranging from 0.1 mol % to 99.9 mol %. Alternatively, in an amount ranging from 0.1 mol % to 1 mol %, mol % to 5 mol %, 5 mol % to 10 mol %, 10 mol % to 25 mol %, 25 mol % to 50 mol %, 50 mol % to 75 mol %, 75 mol % to 90 mol %, 90 mol % to 99 mol %, 99 mol % to 99.9 mol %, or any ranges therebetween. The high temperature suspension additive may include a combination of two or more monomers. When present, the two or more monomers may be included in a mole ratio ranging from a lower limit of about 0.1:99.9, 1:99, 5:95, 10:90, 20:80, 25:75, 30:70, 40:60, or 50:50 to an upper limit of about 99.9:0.1, 99:1, 90:10, 80:20, 75:25, 70:30, 60:40, or 50:50, and wherein the amount may range from any lower limit to any upper limit and encompass any subset between the upper and lower limits and any lower limit may be combined with any other lower limit to recite a range not explicitly recited. In some embodiments, the acrylamide and the N-vinylpyrrolidone are present in a mole ratio of 80:20, 60:40, 50:50, or 40:60. In embodiments, the acrylamide and the 2-acrylamido-2-methyl-1-propanesulfonic acid are present in a mole ratio of 80:20, 60:40, 50:50, or 40:60. In other embodiments, the 2-acrylamido-2-methyl-1-propanesulfonic acid and the N-vinylpyrrolidone are present in a mole ratio of 80:20, 60:40, 50:50, or 40:60.
The high temperature suspension additive may include a thermally unstable crosslinker in an amount ranging from a lower limit of about 0.1 mol % to 20 mol %. Alternatively, in a range of 0.1 mol % to 1 mol %, 1 mol % to 2 mol %, 2 mol % to 3 mol %, 3 mol % to 4 mol %, 4 mol % to 5 mol %, 5 mol % to 10 mol %, 10 mol % to 15 mol %, 15 mol % to 20 mol %, or any ranges therebetween. In one or more embodiments, N,N′-methylenebisacrylamide (MBA) is present in an amount from 0.5 mol % to 10 mol %, or from 1.5 mol % to 2.5 mol %, or 2 mol %, or 1 mol %.
The high temperature suspension additive may include a thermally stable crosslinker in an amount from a lower limit of about 0.1 mol % to 20 mol. %. Alternatively, in a range of 0.1 mol % to 1 mol %, 1 mol % to 2 mol %, 2 mol % to 3 mol %, 3 mol % to 4 mol %, 4 mol % to 5 mol %, 5 mol % to 10 mol %, 10 mol % to 15 mol %, 15 mol % to 20 mol %, or any ranges therebetween.
In one or more embodiments, triallyl isocyanurate (TTT) is present in an amount ranging from 0.5 mol % to 10 mol %, or from 1 mol % to 5 mol %, or 2 mol % to 4 mol %. In embodiments, pentaerythritol allyl ether (PEAE) is present in an amount ranging from 0.5 mol % to 10 mol %, or from 1 mol % to 5 mol %, or 2 mol % to 4 mol %. In some embodiments, triethylglycol divinyl ether (TEGDVE) is present in an amount ranging from 0.5 mol % to 10 mol %, or from 1 mol % to 5 mol %, or 2 mol % to 4 mol %.
In some embodiments, the high temperature suspension additive may be used in a wellbore and/or subterranean formation with a bottom hole static temperature (BHST) ranging from a lower limit of about 275° F. (135° C.), 300° F. (149° C.), 325° F. (163° C.), 350° F. (177° C.), 400° F. (204° C.), or 450° F. to an upper limit of about 550° F. (288° C.), 500° F. (260° C.), 450° F. (232° C.), or 400° F. (204° C.), and wherein the temperature may range from any lower limit to any upper limit and encompass any subset between the upper and lower limits.
Once partially hydrolyzed at wellbore conditions, the high temperature crosslinker may provide viscosity to the fluid such that the fluid has a viscosity in a range of about 5 bc (beardan units of consistency—as measured in a pressurized consistometer in accordance with API RP 10B-2, Recommended Practice for Testing Well Cements, First Edition, July 2005) to about 120 bc. Alternatively, from 5 bc to 10 bc, 10 bc to 25 bc, 25 bc to 50 bc, 50 bc to 75 bc, 75 bc to 100 bc, 100 bc to 120 bc, or any ranges therebetween. Alternatively, the fluid containing the hydrolyzed high temperature suspension additive may have a viscosity as measured by a viscometer in accordance with API RP 10B-2, Recommended Practice for Testing Well Cements, First Edition, July 2005) in a range of about 100 cP (centipoise) to about 600 cP. Alternatively, from 100 cP to 200 cP, 200 cP to 300 cP, 300 cP to 400 cP, 400 cP to 500 cP, 500 cP to 600 cP, or any ranges therebetween.
In embodiments, a cement slurry may include the high temperature suspension additive, a cement, and water. The high temperature suspension additive may be used with any wellbore cement including hydraulic cements such as a Portland cement including API classes A, B, C, G, and H; a slag cement; a pozzolana cement; a gypsum cement; an aluminous cement; a silica cement; a high alkalinity cement; and any combination thereof. Suitable water may include fresh water, saltwater (e.g., water containing one or more salts dissolved therein), brine (e.g., saturated salt water), seawater, and any combination thereof. Generally, the water may be from any source, provided that it does not contain components that might adversely affect the stability and/or performance of the compositions or methods of the present disclosure. The cement slurry may include the high temperature suspension additive in any amount including from 0.1% by weight of cement (bwoc) to 5% bwoc. Alternatively, from 0.1% bwoc to 0.5% bwoc, 0.5% bwoc to 1% bwoc, 1% bwoc to 2% bwoc, 2% bwoc to 3% bwoc, 3% bwoc to 5% bwoc, or any ranges therebetween.
The cement slurry may further include any suitable additive such as any suitable particulate. A suitable particulate for use in the present invention may be any particulate suitable for use in a subterranean formation including, but not limited to, cementitious particulates, weighting agents, proppants, fine aggregate particulates, and any combination thereof. Suitable particulates for use in the present invention may have a diameter ranging from a lower limit of about 0.5 μm, 1 μm, 10 μm, 50 μm, 0.1 mm, or 1 mm to an upper limit of about 10 mm, 1 mm, 0.5 mm, 0.1 mm, or 50 μm, and wherein the diameter may range from any lower limit to any upper limit and encompass any subset between the upper and lower limits. A particulate may be present in a treatment fluid in an amount ranging from a lower limit of about 1%, 5%, 10%, 20%, 30%, 40%, or 50% by weight of treatment fluid to an upper limit of about 99%, 90%, 80%, 70%, 60%, 50%, or 40% by weight of treatment fluid, and wherein the amount may range from any lower limit to any upper limit and encompass any subset between the upper and lower limits.
Suitable weighting agents for use in the present disclosure may be any known weighting agent that is a particulate including, but not limited to, barite, iron oxide, iron carbonate hematite; manganese tetraoxide; galena; silica; siderite; celestite; ilmenite; dolomite; calcium carbonate; and any combination thereof. Suitable proppants for use in the present disclosure may be any known proppant including, but not limited to, sand, bauxite, ceramic materials, glass materials, polymer materials, polytetrafluoroethylene materials, nut shell pieces, cured resinous particulates comprising nut shell pieces, seed shell pieces, cured resinous particulates comprising seed shell pieces, fruit pit pieces, cured resinous particulates comprising fruit pit pieces, wood, composite particulates, and any combination thereof. Suitable composite particulates may comprise a binder and a filler material wherein suitable filler materials include silica, alumina, fumed carbon, carbon black, graphite, mica, titanium dioxide, meta-silicate, calcium silicate, kaolin, talc, zirconia, boron, fly ash, hollow glass microspheres, solid glass, and any combination thereof.
Suitable fine aggregate particulates for use in the present disclosure may include, but are not limited to, fly ash, silica flour, fine sand, diatomaceous earth, lightweight aggregates, hollow spheres, and any combination thereof.
In some embodiments, a high temperature suspension additive may be included in a first fluid that is placed in a wellbore and/or subterranean formation before and/or after a second fluid, wherein the second fluid comprises a plurality of particulates and the high temperature suspension additive. In some embodiments, the concentration of high temperature suspension additive may be different in a first fluid than in a second fluid. In some embodiments, the first fluid may be a spacer fluid and the second fluid may be a treatment fluid.
In some examples, the cement slurry may further include a lightweight additive. The lightweight additive may be included to reduce the density of examples of the cement slurry. For example, the lightweight additive may be used to form a lightweight cement slurry, for example, having a density of less than about 13 ppg. The lightweight additive typically may have a specific gravity of less than about 2.0. Examples of suitable lightweight additives may include sodium silicate, hollow microspheres, gilsonite, perlite, and combinations thereof. Where used, the lightweight additive may be present in an amount in the range of from about 0.1% to about 20% by weight of dry solids, for example. In alternative examples, the lightweight additive may be present in an amount in the range of from about 1% to about 10% by weight of dry solids.
The cement slurry generally should have a density suitable for a particular application. In some embodiments, the cement slurry may have a density in the range of from about 4 pounds per gallon (“1b/gal”) (480 kg/m3) to about 24 lb/gal (2900 kg/m3). In other embodiments, the cement slurry may have a density in the range of about 4 lb/gal (480 kg/m3) to about 17 lb/gal (2040 kg/m3). In yet other embodiments, the cement slurry may have a density in the range of about 8 lb/gal (960 kg/m3) to about 13 lb/gal (1600 kg/m3), about 13 lb/gal (1600 kg/m3) to about 20 lb/gal (2396 kg/m3). In some examples, the cement slurry may be foamed and include water, high temperature suspension additive, a foaming agent, and a gas. Optionally, to provide a cement slurry with a lower density and more stable foam, the foamed cement slurry may further comprise a lightweight additive, for example. With the lightweight additive, a base slurry may be prepared that may then be foamed to provide an even lower density. In some embodiments, the foamed spacer fluid may have a density in the range of from about 4 ppg (479 kg/m3) to about 13 ppg (1558 kg/m3) and, alternatively, about 7 ppg (839 kg/m3) to about 9 ppg (839 kg/m3). In one particular example, a base slurry may be foamed from a density of in the range of from about 9 ppg (839 kg/m3) to about 13 ppg (1558 kg/m3) to a lower density, for example, in a range of from about 7 ppg (839 kg/m3) to about 9 ppg (839 kg/m3).
The gas used in embodiments of the foamed cement slurry may be any suitable gas for foaming the cement slurry, including, but not limited to air, nitrogen, and combinations thereof. Generally, the gas should be present in examples of the foamed cement slurries in an amount sufficient to form the desired foam. In certain embodiments, the gas may be present in an amount in the range of from about 5% to about 80% by volume of the foamed spacer fluid at atmospheric pressure, alternatively, about 5% to about 55% by volume, and, alternatively, about 15% to about 30% by volume.
Where foamed, examples of the cement slurries may comprise a foaming agent for providing a suitable foam. As used herein, the term “foaming agent” refers to a material or combination of materials that facilitate the formation of a foam in a liquid. Any suitable foaming agent for forming a foam in an aqueous liquid may be used in embodiments of the cement slurries. Examples of suitable foaming agents may include, but are not limited to: anionic, nonionic, amphoteric (including zwitterionic surfactants), cationic surfactant, or mixtures thereof, betaines; anionic surfactants such as hydrolyzed keratin; amine oxides such as alkyl or alkene dimethyl amine oxides; cocoamidopropyl dimethylamine oxide; methyl ester sulfonates; alkyl or alkene amidobetaines such as cocoamidopropyl betaine; alpha-olefin sulfonates; quaternary surfactants such as trimethyltallowammonium chloride and trimethylcocoammonium chloride; C8 to C22 alkylethoxylate sulfates; and combinations thereof. Specific examples of suitable foaming additives include, but are not limited to: mixtures of an ammonium salt of an alkyl ether sulfate, a cocoamidopropyl betaine surfactant, a cocoamidopropyl dimethylamine oxide surfactant, sodium chloride, and water; mixtures of an ammonium salt of an alkyl ether sulfate surfactant, a cocoamidopropyl hydroxysultaine surfactant, a cocoamidopropyl dimethylamine oxide surfactant, sodium chloride, and water; hydrolyzed keratin; mixtures of an ethoxylated alcohol ether sulfate surfactant, an alkyl or alkene amidopropyl betaine surfactant, and an alkyl or alkene dimethylamine oxide surfactant; aqueous solutions of an alpha-olefinic sulfonate surfactant and a betaine surfactant, mixtures of an ammonium salt of an alkyl ether sulfate, and combinations thereof. Generally, the foaming agent may be present in embodiments of the foamed cement slurries in an amount sufficient to provide a suitable foam. In some embodiments, the foaming agent may be present in an amount in the range of from about 0.8% to about 5% by volume of the water (“bvow”).
The cement slurry may include a natural pozzolan such as fly ash, silica fume, metakaolin, or combinations thereof. An example of a suitable pozzolan may include fly ash. A variety of fly ash may be suitable, including fly ash classified as Class C and Class F fly ash according to American Petroleum Institute, API Specification for Materials and Testing for Well Cements, API Specification 10, Fifth Ed., Jul. 1, 1990. Class C fly ash includes both silica and lime, so it may set to form a hardened mass upon mixing with water. Class F fly ash generally does not contain a sufficient amount of lime to induce a cementitious reaction, therefore, an additional source of calcium ions is necessary for consolidation embodiments of a cement slurry including Class F fly ash. In some examples, lime may be mixed with Class F fly ash in an amount in the range of about 0.1% to about 100% by weight of the fly ash. In some instances, the lime may be hydrated lime. An example of a suitable pozzolan may include metakaolin. Generally, metakaolin is a white pozzolan that may be prepared by heating kaolin clay to temperatures in the range of about 600° C. to about 800° C. Where used, the metakaolin may be present in an amount in the range of from about 0.1% to about 40% by weight of the cement slurry. For example, the metakaolin may be present in an amount ranging between any of and/or including any of about 0.1%, 10%, about 20%, about 30%, or about 40% by weight of the cement slurry. An additional example of a suitable pozzolan may include a natural pozzolan. Natural pozzolans are generally present on the Earth's surface and set and harden in the presence of hydrated lime and water. Examples including natural pozzolans may include natural glasses, diatomaceous earth, volcanic ash, opaline shale, tuff, and combinations thereof. The natural pozzolans may be ground or unground.
The cement slurry may further include hydrated lime. As used herein, the term “hydrated lime” will be understood to mean calcium hydroxide. In some examples, the hydrated lime may be provided as quicklime (calcium oxide) which hydrates when mixed with water to form the hydrated lime. The hydrated lime may be included in examples of the consolidating embodiments of the spacer fluid, for example, to form a hydraulic composition with the high temperature suspension additive. For example, the hydrated lime may be included in a pozzolan to-hydrated-lime weight ratio of about 10:1 to about 1:1 or a ratio of about 3:1 to about 5:1. Where present, the hydrated lime may be included in the cement slurries in an amount at a point in a range of from about 1% to about 40% by weight of the cement slurry, for example. In some examples, the hydrated lime may be present in an amount ranging between any of and/or including any of about 1%, about 10%, about 20%, about 30%, or about 40% by weight of the cement slurry.
Some examples of the cement slurry may include silica sources in addition to the high temperature suspension additive; for example, crystalline silica and/or amorphous silica. Amorphous silica is a powder that may be included in examples of the cement slurry as a lightweight filler. Amorphous silica is generally a byproduct of a ferrosilicon production process, wherein the amorphous silica may be formed by oxidation and condensation of gaseous silicon suboxide, SiO, which is formed as an intermediate during the process. Examples including additional silica sources may utilize the additional silica source as needed to enhance compressive strength or set times in consolidating embodiments of the cementing slurries.
In consolidating examples of the cement slurry, the cement slurry may consolidate to form a mass that resists deformation. Consolidating examples of the cement slurry may include water, high temperature suspension additive, and a source of calcium and hydroxide ions such as lime, for example. In general, pozzolans are able to participate in the pozzolanic reaction through reaction of the silaceous and/or aluminous components of the pozzolan with calcium ions and hydroxide ions in water. The pozzolanic reaction may cause the cement slurry to form compressive strength. Compressive strength is generally the capacity of a material or structure to withstand axially directed pushing forces. The compressive strength may be measured according to techniques set forth in API RP-10B-2, Recommended Practice for Testing Well Cements, 2nd Edition published April 2013. Compressive strength is generally measured at a specified time after the cement slurry has been prepared and the resultant composition is maintained under specified temperature and pressure conditions. Compressive strength can be measured by either destructive or non-destructive methods. The destructive method physically tests the strength of consolidated cement slurry at various points in time by crushing the samples in a compression-testing machine. The compressive strength is calculated from the failure load divided by the cross-sectional area resisting the load and is reported in units of pound-force per square inch (psi). Non-destructive methods may employ a USA™ ultrasonic cement analyzer, available from Fann® Instrument Company, Houston, TX. Compressive strength values may be determined in accordance with API RP-10B-2, Recommended Practice for Testing Well Cements, 2nd Edition published April 2013.
By way of example, consolidating embodiments of the cement slurry may develop a 24-hour compressive strength in the range of from about 10 psi to about 2000 psi, alternatively, from about 10 psi to about 100 psi, alternatively from about 100 psi to about 1000 psi, alternatively from about 1000 psi to about 1500 psi, or alternatively from about 1500 psi to about 2000 psi. In some examples, the compressive strength values may be determined using destructive or non-destructive methods at a temperature ranging from 100° F. to 200° F.
The cement slurry may further include kiln dust. “Kiln dust,” as that term is used herein, refers to a solid material generated as a by-product of the heating of certain materials in kilns. The term “kiln dust” as used herein is intended to include kiln dust made as described herein and equivalent forms of kiln dust. Depending on its source, kiln dust may exhibit cementitious properties in that 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 may be generated as a by-product of cement production that is removed from the gas stream and collected, for example, in a dust collector. Usually, large quantities of cement kiln dust are collected in the production of cement that are commonly disposed of as waste. The chemical analysis of the cement kiln dust from various cement manufactures varies depending on a number of factors, including the particular kiln feed, the efficiency of the cement production operation, and the associated dust collection systems. Cement kiln dust generally may include a variety of oxides, such as SiO2, Al2O3, Fe2O3, CaO, MgO, SO3, Na2O, and K2O. Problems may also be associated with the disposal of lime kiln dust, which may be generated as a by-product of the calcination of lime. The chemical analysis of lime kiln dust from various lime manufacturers varies depending on several factors, including the particular limestone or dolomitic limestone feed, the type of kiln, the mode of operation of the kiln, the efficiencies of the lime production operation, and the associated dust collection systems. Lime kiln dust generally may include varying amounts of free lime and free magnesium, limestone, and/or dolomitic limestone and a variety of oxides, such as SiO2, Al2O3, Fe2O3, CaO, MgO, SO3, Na2O, and K2O, and other components, such as chlorides.
The cement slurries may further include barite. In some examples, the barite may be present in the cement slurries in an amount in the range of from about 1% to about 60% by weight of the cement slurries (e.g., about 5%, about 10%, about 15%, about 20%, about 25%, about 30%, about 35%, about 40%, about 45%, about 50%, about 55%, etc.). In some examples, the barite may be present in the cement slurries in an amount in the range of from about 1% to about 35% by weight of the cement slurries. In some examples, the barite may be present in the cement slurries in an amount in the range of from about 1% to about 10% by weight of the cement slurries. Alternatively, the amount of barite may be expressed by weight of dry solids. For example, the barite may be present in an amount in a range of from about 1% to about 99% by weight of dry solids (e.g., about 1%, about 5%, about 10%, about 20%, about 30%, about 40%, about 50%, about 60%, about 70%, about 80%, about 90%, about 99%, etc.). In some examples, the barite may be present in an amount in the range of from about 1% to about 20% and, alternatively, from about 1% to about 10% by weight of dry solids.
In some embodiments, the cement slurry may further include one or more of slag, perlite, shale, amorphous silica, or metakaolin. These additives may be included in the cement slurries to improve one or more properties of the cement slurry. The cement slurries may further include slag. Slag is generally a granulated, blast furnace by-product from the production of cast iron including the oxidized impurities found in iron ore. Where used, the slag may be present in an amount in the range of from about 0.1% to about 40% by weight of the cement slurry. The cement slurry may further include perlite. Perlite is an ore and generally refers to a naturally occurring volcanic, amorphous siliceous rock including mostly silicon dioxide and aluminum oxide. Perlite may be expanded and/or unexpanded as suitable for a particular application. The expanded or unexpanded perlite may also be ground, for example. Where used, perlite may be present in an amount in the range of from about 0.1% to about 40% by weight of the cement slurry. For example, perlite may be present in an amount ranging between any of and/or including any of about 0.1%, about 10%, about 20%, about 30%, or about 40% by weight of the cement slurry. The cement slurry may further include shale. A variety of shales are suitable, including those including silicon, aluminum, calcium, and/or magnesium. Examples of suitable shales include vitrified shale and/or calcined shale. Where used, the shale may be present in an amount in the range of from about 0.1% to about 40% by weight of the cement slurry. For example, the shale may be present in an amount ranging between any of and/or including any of about 0.1%, about 10%, about 20%, about 30%, or about 40% by weight of the cement slurry.
The cement slurry may further include a free water control additive. As used herein, the term “free water control additive” refers to an additive included in a liquid for, among other things, reducing or preventing the presence of free water in the liquid. Free water control additive may also reduce or prevent the settling of solids. Examples of suitable free water control additives include, but are not limited to, bentonite, amorphous silica, hydroxyethyl cellulose, and combinations thereof. The free water control additive may be provided as a dry solid in some embodiments. Where used, the free water control additive may be present in an amount in the range of from about 0.1% to about 16% by weight of dry solids, for example. In alternative embodiments, the free water control additive may be present in an amount in the range of from about 0.1% to about 2% by weight of dry solids.
Optionally, fluid-loss-control additives may be included in the cement slurry, for example, decrease the volume of fluid that is lost to the subterranean formation. Examples of suitable fluid-loss-control additives include, but not limited to, certain polymers, such as hydroxyethyl cellulose, carboxymethylhydroxyethyl cellulose, copolymers of 2-acrylamido-2-methylpropanesulfonic acid and acrylamide or N,N-dimethylacrylamide, and graft copolymers including a backbone of lignin or lignite and pendant groups including at least one member selected from the group consisting of 2-acrylamido-2-methylpropanesulfonic acid, acrylonitrile, and N,N-dimethylacrylamide.
Optionally, lost-circulation materials may be included in the cement slurries to, for example, help prevent the loss of fluid circulation into the subterranean formation. Examples of lost-circulation materials include but are not limited to, cedar bark, shredded cane stalks, mineral fiber, mica flakes, cellophane, calcium carbonate, ground rubber, polymeric materials, pieces of plastic, grounded marble, wood, nut hulls, formica, corncobs, cotton hulls, and combinations thereof.
Optionally, set accelerators may be included in consolidating examples of cement slurries, for example, increase the rate of setting reactions. Control of setting time may allow for the ability to adjust to wellbore conditions or customize set times for individual jobs. Examples of suitable set accelerators may include, but are not limited to, aluminum sulfate, alums, calcium chloride, calcium sulfate, gypsum-hemihydrate, sodium aluminate, sodium carbonate, sodium chloride, sodium silicate, sodium sulfate, ferric chloride, or a combination thereof.
Optionally, set retarders may be included in consolidating examples of cement slurries to, for example, increase the thickening time of the cement slurries. Examples of suitable set retarders include, but are not limited to, ammonium, alkali metals, alkaline earth metals, borax, metal salts of calcium lignosulfonate, carboxymethyl hydroxyethyl cellulose, sulfoalkylated lignins, hydroxycarboxy acids, 5-chloro-2-methyl-3 (2H)-isothiazolone mixture with 2-methyl-3 (2H)-isothiazolone, copolymers of 2-acrylamido-2-methylpropane sulfonic acid salt and acrylic acid or maleic acid, saturated salt, or a combination thereof. One example of a suitable sulfoalkylated lignin includes a sulfomethylated lignin.
As previously mentioned, the cement slurries may consolidate after placement in the wellbore. By way of example, the cement slurries may develop gel and/or compressive strength when left in the wellbore. As a specific example of consolidation, when left in a wellbore annulus (e.g., between a subterranean formation and the pipe string disposed in the subterranean formation or between the pipe string and a larger conduit disposed in the subterranean formation), the cement slurry may consolidate to develop static gel strength and/or compressive strength. The consolidated mass formed in the wellbore annulus may act to support and position the pipe string in the wellbore and bond the exterior surface of the pipe string to the walls of the wellbore or to the larger conduit. The consolidated mass formed in the wellbore annulus may also provide a substantially impermeable barrier to seal off formation fluids and gases and consequently also serve to mitigate potential fluid migration. The consolidated mass formed in the wellbore annulus may also protect the pipe string or other conduit from corrosion.
The cement slurries may be prepared in accordance with any suitable technique. In some examples, the desired quantity of water may be introduced into a mixer (e.g., a cement blender) followed by a dry blend of the spacer fluid components. The dry blend may comprise the high temperature suspension additive and additional solid additives such as those described above. Additional liquid additives, if any, may be added to the water as desired prior to, or after, combination with the dry blend. This mixture may be agitated for a sufficient period of time to form a pumpable slurry. By way of example, pumps may be used for delivery of this pumpable slurry into the wellbore.
In some embodiments, a high temperature suspension additive may be provided in wet or dry form. In some embodiments, a high temperature suspension additive may be added to a treatment fluid on-site or off-site of the wellbore location.
The components of the cement composition may be combined in any order desired to form a cement composition that can be placed into a subterranean formation. In addition, the components of the cement compositions may be combined using any mixing device compatible with the composition, including a bulk mixer, for example. In one particular example, a cement composition may be prepared by dry blending the solid components of the cement composition at a bulk plant, for example, and thereafter combining the dry blend with water when desired for use. For example, a dry blend may be prepared that includes the high temperature suspension additive and the other dry cement components. Liquid additives (if any) may be combined with the water before the water is combined with the dry components or added directly to a mixer tub. In some examples, a jet mixer may be used, for example, to continuously mix the dry blend including the cement composition, for example, with the water as it is being pumped to the wellbore.
In some examples, the high temperature suspension additive may be included in a spacer fluid. Spacers, also sometimes referred to as displacement fluids, wash fluids, or inverter fluids, are placed in the wellbore after drilling and before cementing. Spacers prepare the wellbore to receive cement. For instance, a spacer may fully displace drilling fluid from the wellbore annulus and/or condition the casing and wellbore surface to bond with cement. Drilling fluid can contaminate the cement, which can eventually lead to issues such as incompatibility, poor bonding as well as suppression of compressive strength development. The presence of drilling fluid filter cake over the casing may affect the bonding between the casing and cement and lead to formation of micro channels. Accordingly, spacers often remove any cakes from the drilling fluid and leave the casing and annulus water-wet to receive cement. A spacer fluid may include water and the high temperature suspension additive. Spacer fluids may be formulated by mixing a spacer dry blend comprising the high temperature suspension additive and water. The spacer dry blend may include the high temperature suspension additive along with any other dry components for a particular application. In examples a spacer fluid may include the high temperature suspension additive in any amount including from 0.01% by bwob (by weight of spacer dry blend) to 50% bwob. Alternatively, from 0.01% bwob to 0.05% bwob, 0.05% bwob to 0.1% bwob, 0.1% bwob to 0.5% bwob, 0.5% bwob to 1% bwob, 1% bwob to 2% bwob, 2% bwob to 3% bwob, 3% bwob to 5% bwob, 5% bwob to 15% bwob, 15% bwob to 25% bwob, 25% bwob to 50% bwob, or any ranges therebetween.
To be effective, the spacer can have certain characteristics. For example, the spacer may be compatible with the displaced fluid and the cement. This compatibility may also be present at downhole temperatures and pressures. In some instances, it is also desirable for the spacer to leave surfaces in the wellbore water wet, thus facilitating bonding with the cement. A number of different rheological properties may be important in the design of a spacer, including yield point, plastic viscosity, gel strength, and shear stress, among others. While rheology can be important in spacer design, conventional spacers may not have the desired rheology at downhole temperatures. For instance, conventional spacers may experience undesired thermal thinning at elevated temperatures. As a result, conventional spacers may not provide the desired displacement in some instances or lead to poor suspension in other instances.
In some examples, the spacer dry blend may include a solid scouring material, for example, to scrub and facilitate removal of solid filter cake on wellbore surfaces. Examples of suitable solid scouring materials may include, but are not limited to, pumice, perlite, other volcanic glasses, fumed silica, and fly ash, among others. The solid scouring material may be present in the spacer dry blend in any suitable amount, including, but not limited to, an amount of about 1% bwob to about 99.9% bwob. In specific embodiments, the solid scouring material may be present in an amount of about 1% bwob to 25% bwob, 25% bwob to 50% bwob, 50% bwob to 75% bwob, 90% to about 99%, or any ranges therebetween.
In some examples, the spacer dry blend may include a biopolymer gum. Examples of suitable biopolymer gums may include, but are not limited to polysaccharides such as, xanthan gum, diutan gum, welan gum, scleroglucan gum, and combinations thereof. The biopolymer gum may be present in the spacer dry blend in any suitable amount, including, but not limited to, an amount of from 0.01% by bwob (by weight of spacer dry blend) to 5% bwob. Alternatively, from 0.01% bwob to 0.05% bwob, 0.05% bwob to 0.1% bwob, 0.1% bwob to 0.5% bwob, 0.5% bwob to 1% bwob, 1% bwob to 2% bwob, 2% bwob to 3% bwob, 3% bwob to 5% bwob, or any ranges therebetween. The spacer fluid may further include a surfactant. Any of a variety of surfactants may be included that may be capable of wetting well surfaces (e.g., water- or oil-wetting), such as the wellbore wall and casing surface. In some embodiments, both a water-wetting surfactant and an oil-wetting surfactant may be included in the spacer fluid. Examples of suitable wetting surfactants may include alcohol ethoxylates, alcohol ethoxysulfates, alkyl phenol ethoxylates (e.g., nonyl phenol ethoxylates), glycol ethers, and combinations thereof. Certain of the wetting surfactants may be used as water-soluble salts. For example, the wetting surfactants may be selected from alkali metal, alkaline earth metal, ammonium, and alkanolammonium salts of alcohol ethoxylates, alcohol ethoxysulfates, and alkyl phenol ethoxylates. The surfactant may be present in the spacer dry blend in any suitable amount, including, but not limited to, an amount of from 0.01% by bwob (by weight of spacer dry blend) to 5% bwob. Alternatively, from 0.01% bwob to 0.05% bwob, 0.05% bwob to 0.1% bwob, 0.1% bwob to 0.5% bwob, 0.5% bwob to 1% bwob, 1% bwob to 2% bwob, 2% bwob to 3% bwob, 3% bwob to 5% bwob, or any ranges therebetween.
The spacer fluid may further include a dispersant. Without limitation, suitable dispersants may include any of a variety of commonly used cement dispersants, such as sulfonated dispersants; sulfonated polymer dispersants; naphthalene sulfonates; melamine sulfonates; sulfonated melamine formaldehyde condensate; sulfonated naphthalene formaldehyde condensate; sulfonate acetone formaldehyde condensate; ethoxylated polyacrylates: or combinations thereof. The dispersant may be present in the spacer dry blend in any suitable amount, including, but not limited to, an amount of from 0.01% by bwob (by weight of spacer dry blend) to 5% bwob. Alternatively, from 0.01% bwob to 0.05% bwob, 0.05% bwob to 0.1% bwob, 0.1% bwob to 0.5% bwob, 0.5% bwob to 1% bwob, 1% bwob to 2% bwob, 2% bwob to 3% bwob, 3% bwob to 5% bwob, or any ranges therebetween.
Spacer fluids may further include a weighting agent. Weighting agents may be included in the spacer dry blend, for example, to provide the spacer fluid with a desired density. Examples of suitable weighting agents include, for example, such as barite, manganese tetraoxide, iron oxide, calcium carbonate, or iron carbonate. Weighting agents may be included in any suitable amount, including, but not limited to, from about 1% bwob to about 99% bwob, about 50% bwob to about 99% bwob, or about 75% bwob to about 99% bwob based on a total weight of the spacer dry blend.
The spacer fluids generally should have a density suitable for a particular application. In some embodiments, the spacer fluids may have a density in the range of from about 4 pounds per gallon (“1b/gal”) (480 kg/m3) to about 24 lb/gal (2900 kg/m3). In other embodiments, the spacer fluids may have a density in the range of about 4 lb/gal (480 kg/m3) to about 17 lb/gal (2040 kg/m3). In yet other embodiments, the spacer fluids may have a density in the range of about 8 lb/gal (960 kg/m3) to about 13 lb/gal (1600 kg/m3), about 13 lb/gal (1600 kg/m3) to about 20 lb/gal (2396 kg/m3). Embodiments of the spacer fluids may be foamed or unfoamed or include other means to reduce their densities known in the art, such as lightweight additives. Those of ordinary skill in the art, with the benefit of this disclosure, will recognize the appropriate density for a particular application.
As previously described, the spacer dry blend may be combined with water to form a spacer fluid, which may then be introduced into the wellbore. The water used in an embodiment of the spacer fluids may include, for example, freshwater, saltwater (e.g., water containing one or more salts dissolved therein), brines, seawater, or any combination thereof. Generally, the water may be from any source, provided that the water does not contain an excess of compounds that may undesirably affect other components in the spacer fluid. The water is included in an amount sufficient to form a pumpable spacer fluid. In some embodiments, the water may be included in the spacer fluids in an amount in the range of from about 15 wt. % to about 95 wt. % based on a total weight of the spacer fluid. In other embodiments, the water may be included in the spacer fluids in an amount in the range of from about 25 wt. % to about 85 wt. % or about 50 wt. % to about 75 wt. % based on a total weight of the spacer fluid. The spacer dry blend may be included in the spacer fluid in any suitable amount, including about 5 wt. % to about 50 wt. %, about 10 wt. % to about 60 wt. %, or about 20 wt. % to about 50 wt. % based on a total weight of the spacer fluid.
Suitable spacer fluids may be prepared in accordance with any suitable technique. Without limitation, the desired quantity of water may be introduced into a mixer (e.g., a cement blender) followed by the spacer dry blend. Additional liquid additives and/or dry additives, if any, may be added to the water as desired prior to, or after, combination with the dry blend. This mixture may be agitated for a sufficient period of time to form a pumpable slurry. By way of example, pumps may be used for delivery of this pumpable slurry into the wellbore. As will be appreciated, the spacer fluid and/or the spacer dry blend may be prepared at the well site or prepared offsite and then transported to the well site. If prepared offsite, the spacer dry blend and/or spacer fluid may be transported to the well site using any suitable mode of transportation, including, without limitation, a truck, railcar, barge, or the like. Alternatively, the spacer fluid and/or spacer dry blend may be formulated at the well site, for example, where the components of the spacer fluid and/or spacer dry blend may be delivered from a transport (e.g., a vehicle or pipeline) and then mixed prior to placement downhole. As will be appreciated by those of ordinary skill in the art, with the benefit of this disclosure, other suitable techniques for preparing the spacer fluids may be used in accordance with embodiments.
The spacer may have a viscosity at surface temperature and pressure sufficient to allow it to suspend any particles additives, such as barite, while still allowing it to be pumped downhole. In the wellbore, the spacer may maintain a viscosity sufficient to allow it to suspend any particle additives, while still allowing it to circulate through and out of the wellbore. The spacer may further maintain a viscosity upon return to surface pressure or temperature sufficient to allow it to exit the wellbore. The spacer may also further maintain its viscosity to allow it to continue to suspend any particles additives, such as barite, until it reaches a holding tank, through any cleaning or testing process, or until it is returned to the wellbore, as applicable.
An example method may include a method of displacing a first fluid from a wellbore, the wellbore penetrating a subterranean formation. The method may include providing a spacer fluid that comprises the high temperature suspension additive and water. One or more additives may also be included in the spacer fluid as discussed herein. The method may further comprise introducing the spacer fluid into the wellbore to displace at least a portion of the first fluid from the wellbore. In some examples, the spacer fluid may displace the first fluid from a wellbore annulus, such as the annulus between a pipe string and the subterranean formation or between the pipe string and a larger conduit. In some examples, the first fluid displaced by the spacer fluid includes a drilling fluid. By way of example, the spacer fluid may be used to displace the drilling fluid from the wellbore. In addition to displacement of the drilling fluid from the wellbore, the spacer fluid may also remove the drilling fluid from the walls of the wellbore. Additional steps in examples of the method may comprise introducing a pipe string into the wellbore, introducing a cement composition into the wellbore with the spacer fluid separating the cement composition and the first fluid. In an embodiment, the cement composition may be allowed to set in the wellbore. The cement composition may include, for example, cement, high temperature suspension additive, and water.
An example of using spacer fluid 20 including the high temperature suspension additive will now be described with reference to
As illustrated, a cement composition 38 comprising the high temperature suspension additive may be introduced into wellbore 24. For example, cement composition 38 may be pumped down the interior of casing 34. Pump 6 shown on
Spacer fluid 20 comprising the high temperature suspension additive may be used to separate drilling fluid 26 from cement composition 38 comprising the high temperature suspension additive. The previous embodiments described with reference to
Referring now to
The exemplary cement compositions including the high temperature suspension additive disclosed herein may directly or indirectly affect one or more components or pieces of equipment associated with the preparation, delivery, recapture, recycling, reuse, and/or disposal of the cement compositions and associated cement compositions. For example, the cement compositions may directly or indirectly affect one or more mixers, related mixing equipment, mud pits, storage facilities or units, composition separators, heat exchangers, sensors, gauges, pumps, compressors, and the like used to generate, store, monitor, regulate, and/or recondition the cement compositions. The disclosed cement compositions may also directly or indirectly affect any transport or delivery equipment used to convey the cement compositions to a well site or downhole such as, for example, any transport vessels, conduits, pipelines, trucks, tubulars, and/or pipes used to compositionally move the cement compositions from one location to another, any pumps, compressors, or motors (e.g., topside or downhole) used to drive the suspension additive, or fluids containing the same, into motion, any valves or related joints used to regulate the pressure or flow rate of the cement compositions, and any sensors (i.e., pressure and temperature), gauges, and/or combinations thereof, and the like. The disclosed cement compositions may also directly or indirectly affect the various downhole equipment and tools that may come into contact with the cement compositions such as, but not limited to, wellbore casings, wellbore liner, completion string, insert strings, drill string, coiled tubing, slickline, wireline, drill pipe, drill collars, mud motors, downhole motors and/or pumps, cement pumps, surface-mounted motors and/or pumps, centralizers, terrorizers, scratchers, floats (e.g., shoes, collars, valves, etc.), logging tools and related telemetry equipment, actuators (e.g., electromechanical devices, hydromechanical devices, etc.), sliding sleeves, production sleeves, plugs, screens, filters, flow control devices (e.g., inflow control devices, autonomous inflow control devices, outflow control devices, etc.), couplings (e.g., electro-hydraulic wet connect, dry connect, inductive coupler, etc.), control lines (e.g., electrical, fiber optic, hydraulic, etc.), surveillance lines, drill bits and reamers, sensors or distributed sensors, downhole heat exchangers, valves and corresponding actuation devices, tool seals, packers, cement plugs, bridge plugs, and other wellbore isolation devices, or components, and the like.
To facilitate a better understanding of the present disclosure, the following examples of some embodiments are given. In no way should such examples be read to limit, or to define, the scope of the disclosure.
In this example, a high temperature suspension additive was tested in a cement. The high temperature suspension additive was a polymer containing a mixture of acrylamide/N-vinylpyrrolidone (Ac/NVP) in a mole ratio of 60:40 crosslinked with 2% N,N′-methylenebisacrylamide (MBA) and 2% triallyl isocyanurate (TTT). In one or more embodiments, a method of calculating the critical concentration (C*) of the polymer mixture Ac/NVP in a mole ratio of 60:40 crosslinked with 2% MBA and 2% TTT based on titration data is illustrated in
In this example, the high temperature suspension additive was tested in a spacer fluid. A first high temperature suspension additive was prepared using acrylamide and 2% triallyl isocyanurate. A first spacer fluid was prepared with 4 grams of the first high temperature suspension additive, 1 gram of polysaccharide-based suspension additive, 695.9 grams of barite, 34.24 grams of volcanic rock and 701.73 grams of water. The rheology of the first spacer fluid was tested at 80° F. using a Fann 35 viscometer. The results of the rheology test are shown in Table 2 where the first dial reading is the reading as RPMs are ramped up and the second dial reading is an RPMs are ramped down. A second spacer fluid was prepared with 1 gram of the polysaccharide-based suspension additive, 695.9 grams of barite, 34.24 grams of volcanic rock and 701.73 grams of water. The results of the rheology test are shown in Table 3.
The first spacer fluid was aged at 350° F. for a period of 30 minutes and 3.5 hours at 350° F. in a consistometer. The rheology of the first spacer fluid was measured at 80° F. after the 30 minutes and 3.5 hour mark and the data of which is shown in Table 4 and Table 5.
A second high temperature suspension additive was prepared using acrylamide and N-vinylpyrrolidone in a 60:40 ratio with 2% N,N′-methylenebisacrylamide crosslinker and 2% triallyl isocyanurate crosslinker. A third spacer fluid was prepared with 5 grams of the second high temperature suspension additive 695.9 grams of barite, 34.24 grams of volcanic rock and 701.73 grams of water. The third spacer fluid was conditioned at 350° F. and the rheology was tested at 80° F. using a Fann 35 viscometer. The results of the rheology test are shown in Table 6. A graph of the results of the rheology test are shown in
The third spacer fluid was further conditioned at 400° F. and the rheology was measured again. The results of the conditioning are shown in Table 7 and in
A third high temperature suspension additive was prepared using acrylamide with 2% N,N′-methylenebisacrylamide crosslinker and 2% triallyl isocyanurate crosslinker. A fourth spacer fluid was prepared with 4 grams of the third high temperature suspension additive, 1 gram of a polysaccharide-based suspension additive 695.9 grams of barite, 34.24 grams of volcanic rock and 701.7 grams of water. The rheology of the fourth spacer fluid was evaluated and the results thereof are shown in Table 8. The fourth spacer fluid was conditioned at 350° F. for 3 hours and the rheology was tested at 80° F. using a Fann 35 viscometer. The results of the rheology test are shown in Table 9.
A fourth high temperature suspension additive was prepared using acrylamide with 2% N,N′-methylenebisacrylamide crosslinker and 2% triethylene glycol divinyl ether crosslinker. A fifth spacer fluid was prepared with 2.92 lb/bbl of the fourth high temperature suspension additive, 0.29 lb/bbl polysaccharide-based suspension additive, 20 lbs/bbl volcanic rock, and blended to a density of 16 lbs/gallon. The fifth spacer fluid was tested in a consistometer with a 350° F. sweep. The results of the test are shown in
In this example, a number of high temperature suspension additives were prepared and tested. The prepared high temperature suspension additives were tested in a clean spacer fluid using the formulation from Table 10, a spacer fluid with cement contamination using the spacer formulation from Table 11, a spacer fluid design for longevity testing using the formulation in Table 12, and a water yielding fluid using the formulation in Table 13. The formulation for the high temperature suspension additives is shown in Table 14. The high temperature suspension additives include polyacrylamide (PAc), polyacrylamide/2-acrylamido-2-methyl-1-propanesulfonic acid (PAc/AMPS), 2-acrylamido-2-methyl-1-propanesulfonic acid/N-vinylpyrrolidone (AMPS/NVP), acrylamide/N-vinylpyrrolidone (Ac/NVP), and N-vinylpyrrolidone (NVP). The results of the tests are shown in Table 15.
To facilitate a better understanding of the present disclosure, the following examples of some embodiments are given. In no way should such examples be read to limit, or to define, the scope of the disclosure.
In this Example, polymer entanglement concentration (P*) was measured for a Ac/NVP (60:40) 2% MBA 2% TTT polymer. A 1 g amount of polymer was dispersed in 50 g of DI water. The solution was placed in a Chandler 5550 rheometer with an R1B5X geometry and sheared at 100 rpm for the duration of the experiment. The solution was heated to 400° F. over 20 minutes while keeping a constant 1000 psi of N2 pressure. The solution was held at 400° F. for 40 minutes and then cooled to room temperature. The resulting solutions with yielded polymer was then used to preform the apparent viscosity (AVIS) measurements. Serial dilutions of four iterations of the polymer Ac/NVP (60:40) 2% MBA 2% TTT were measured at a shear rate of 3 rpm. The results of the AVIS measurements are shown in Table 16. A line of best fit was calculated using linear least squares for AVIS/concentration and Ln (AVIS)/concentration and the intercept polymer entanglement concentration (P*) was calculated.
Accordingly, the present disclosure is related to a high temperature suspension additive and methods of using the high temperature suspension additive in wellbore operations. The methods may include any of the various features disclosed herein, including one or more of the following statements.
It should be understood that the compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the elements that it introduces.
For the sake of brevity, only certain ranges are explicitly disclosed herein. However, ranges from any lower limit may be combined with any upper limit to recite a range not explicitly recited, as well as, ranges from any lower limit may be combined with any other lower limit to recite a range not explicitly recited, in the same way, ranges from any upper limit may be combined with any other upper limit to recite a range not explicitly recited. Additionally, whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range are specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values even if not explicitly recited. Thus, every point or individual value may serve as its own lower or upper limit combined with any other point or individual value or any other lower or upper limit, to recite a range not explicitly recited.
Therefore, the present disclosure is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular examples disclosed above are illustrative only, as the present disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Although individual examples are discussed, the disclosure covers all combinations of all those examples. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. It is therefore evident that the particular illustrative examples disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present disclosure. If there is any conflict in the usages of a word or term in this specification and one or more patent(s) or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.
