CA1185777A - Aqueous treatment fluid and method of use - Google Patents
Aqueous treatment fluid and method of useInfo
- Publication number
- CA1185777A CA1185777A CA000390787A CA390787A CA1185777A CA 1185777 A CA1185777 A CA 1185777A CA 000390787 A CA000390787 A CA 000390787A CA 390787 A CA390787 A CA 390787A CA 1185777 A CA1185777 A CA 1185777A
- Authority
- CA
- Canada
- Prior art keywords
- component
- treatment fluid
- fluid
- water
- percent
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Expired
Links
Landscapes
- Soil Conditioners And Soil-Stabilizing Materials (AREA)
Abstract
ABSTRACT OF THE DISCLOSURE
A composition designed for dissolution or dispersion in water to give an aqueous treatment fluid which is compatible with cement slurries and with drilling muds and a method of using same to displace a drilling mud from a borehole which penetrates a subterranean formation.
The compositon comprises a water soluble viscosifier which increases the viscosity of water under mixing and handling conditions but which becomes substantially insoluble in water when exposed to temperatures encountered downhole in a wellbore; a thickener, which is soluble or dispersible in and which increases the viscosity of water at temperatures experienced under downhole conditions; and a third component, a dispersant, which enhances the dispersibility of the viscosifier in water and thereby permits it to go smoothly into solution, and water. The resultant aqueous treatment fluid, at a viscosity of greater than 0.1 and less than 7.5
A composition designed for dissolution or dispersion in water to give an aqueous treatment fluid which is compatible with cement slurries and with drilling muds and a method of using same to displace a drilling mud from a borehole which penetrates a subterranean formation.
The compositon comprises a water soluble viscosifier which increases the viscosity of water under mixing and handling conditions but which becomes substantially insoluble in water when exposed to temperatures encountered downhole in a wellbore; a thickener, which is soluble or dispersible in and which increases the viscosity of water at temperatures experienced under downhole conditions; and a third component, a dispersant, which enhances the dispersibility of the viscosifier in water and thereby permits it to go smoothly into solution, and water. The resultant aqueous treatment fluid, at a viscosity of greater than 0.1 and less than 7.5
Description
7~7 AQUEOUS TREATMENT FLUID AN~ METHOD OF USE
The invention pertains to a composition which when intimately mixed with water forms an aqueous treatment fluid suitable for use as a well completion or spacer fluid in the drilling of oil and gas wells or other boreholes in subterranean formations. It also relates to a method of using such an aqueous treatment fluld as a spacer composition, particularly in the context of cemerlting casing in a wellbore.
Rotary drilling techniques are commonly used for drilling wells in the earth thrcugh subterranean formations of sandstone, shale, limestone, etc. In such rotary drilling, a drilling fluid or "drilling mud" is circulated between the surface of the earth and the bottom of the well. Drilling muds which are commonly used include water-based muds comprising both clay and polymer containing muds, oil-based muds and emulsions.
Drilling muds serve many useful purposes including the removal of earth and rock cuttings from the well, control of foxmation pressures, and cooling and lubri-cation of the drill bit which is used in drilling thewell. However, there are also certain detrimental characteristics associated with drilling muds. Among 28,628-F -1-~L~8~777 the problems associated with drilling muds is that drilllng muds tend to flow from the well into exposed permeable formatlons with ~he result that mud solids are filtered out on the wall of the well and a filter cake is formed. Even thin filter cakes are detrimental in the completion of wells because they sometimes interfere with the formation of a good cement bond between the wall of the wellbore and the casing posi-tioned in this wellbore. AlSo, drilling muds fre-quently contain components which are incompatible witha fluid which one may desire to inject into a well containing such mud. For example, it has long been recognized that if certain cement slurries containing free polyvalent metal cations, especially calcium, are brought into contact with muds containing clay or certain polymers, a very viscous and detrimental plug can form in the vicinity of the mud-cement interface.
The problems created by such a highly viscous mud-cement interface are well known in the well cementing art.
Another example of mud-cement incompatibility is that lignins, which are frequently used as dispersants in high density muds, can cause excessive retardation in cements if cement becomes comingled with the mud.
Consequently, various techniques have been devised for the removal of drilling muds from a borehole, particularly in the contex-t of injecting a fluid into the borehole which is incompatible with the mud, more specifically in the context of cementing. A common techni~ue is to employ a "spacer" or a "chemical wash".
Although it not always clear in the literature whether fluid is a spacer or a chemical wash, a spacer is generally characterized as a thickened composition which functions primarily as a fluid piston in dis-placing the mud. Spacers frequently contain appreciable 28,628-F -2---3~
quantities of weighting agents to impart a desired density ~o the spacer fluid. Chemical washes, on the other hand, are generally thin fluids which are effective principally as ~he result of turbulance, dilution, and surfactant action on the mud and mud filter cake.
Chemical washes often contain solids to act as an abrasive but the solids content is significantly lower than in spacers because the washes are generally too thin to have good solids carrying capacity.
The art of preparing and using spacers and chemical washes is discussed in detail in U.S. Patent 4,083,407. Of particular interest is U.S. Patent 3,291,211, Savins et al. which describes a process for removing mudcake from the wall of a borehole and then cementing the casing in such a wellbore by using a fluid said to have "viscoelastic" properties as a spacer to displace a mudcake from the annulus. The vi.scoelastic fluid is said to be prepared from an oil--miscible solvent for use with an oil-based drilling mud ~0 or from water or water-miscible solvent in the case of use with a water-based drilling mud. Viscoelastic properties are imparted to the spacer fluids by the addition of various solutes to the respective solvents.
Among the solutes mentioned are high molecular weight cellulose derivatives such as carboxymethylcellulose (CMC) and hydxoxyethylcellulose (HEC), polyethylene oxides, sulfonated polystyrenes, polyacrylamides and partially hydrolyzed polyacrylamides, natural gums, fatty acid soaps, etc. Savins prefers that his visco-elastic fluids be such that a normal stress of at least2000 dynes per square centimeter is developed in a rotating viscometer.
28,628-F -3-~4~
In U.SO Patent 4,141,843, Watson discloses a nondamaging spacer fluid comprising weighting agents dispersed in water, a polymer viscosifier and several other components. The spacer is said to be stable over a temperature range of about 32-300F for extended periods of time. The fluids described by Watson employ as preferred viscosifiers water soluble polysaccharides, especially hydroxyalkylcelluloses having two to three carbon atoms in the hydroxyalkyl groups. The spacer fluids prepared by Watson are said to be non Newtonian in character, i.e. they have yield points which are not equal to zero.
In a publication entitl~d "Applied Engineered Cementing'l (1969) by Byron Jackson, Inc., pages 54-55, a "cementing preflush", or spacer as the term is used herein, designated Mud-Sweep is described as a high viscosity, aqueous solution having a density which can be adjusted from 8.6 to as high as 1~ pounds per gallon.
Th~t spacer is said to operate on a "viscous sweep"
principle to accomplish maximum mud removal regardless oE the flo~ rate. It is said not to be necessary to attain turbulent flow to achieve excellent mud removal.
The composition of the spacer is not disclosed, however it is stated to be highly viscous yet thixotropic, to contain de-oiling chemicals that tend to preferentially water wet the casing and wellbore and to also contain additives that "flocculate clay-base drilling muds, forming a viscous interface that aids in sweeping mud from the annulus". Obviously, that spacer is incompatible with many drilling fluids.
In U.S. Patent 4,083,407 CMC and HEC are employed by Griffin et al. as fluid loss control additives.
28,628-F -4-The spacer itself is thickened with a polyvalen~ metal siiicate.
The present invention has both the properties of a spacer and a chemical wash. It comprises a composi-tion especially designed to be soluble ox dispersiblein water providing a resultant aqueous treatment 1uid of sufficient thickness or l'viscosity" to permit sus-pension thereof of a quantity of weighting agent suf-ficient to impart a desired density to the thus weighted aqueous treatment fluid. The treatment fluid is prepared wi-th suitabl~ viscosifiers and thickeners such that a thick fluid is a~tained that is sufficiently viscous to suspend the desired weighting agents upon mixing, blending, handling and transportation of the so--weighked fluid at temperatures encountered during field operations and yet the aqueous treatmen~ fluid will experience a sufficient viscosity loss under downhole conditions to attain a kinematic viscosity which permi-ts the treatment fluid to go into turbulent ~low at reasonable pumping rates, e.g. less than 16, preerably less than 12 and more preferably less than 8 barrels per minute.
Stated another way, the treatment fluid is designed to be a pseudoplastic fluid at temperatures of mixing and handling yet become a Newtonian fluid at the temperatures encountered under downhole conditions when the fluid is pumped in the annulus between a borehole and a casing or some other void space in a subterranean borehole. Since the fluid is designed to go into turbulent flow, the tuxbulence generally will be suf-ficient to suspend the solid particulate materials which are commonly employed as weighting agents.
However, it is preferable that the treatment fluid 28,628-F -5---6~
maintain sufficient viscosity under downhole conditions to suspend such particulate material und~r static or plug or laminar flow conditions. Consequently, it is preferred that under downhole temperature conditions a kinematic viscosity be maintained equal to 15 centpp _se, where P is defined as the density of the treatment fluid in pounds per gallon. This is particularly desirable if the possibility of pump s~oppage or break-down is present.
In the invention, the preferred composition to be used in obtaining such an aqueous treatment fluid is prepared by combining at least three components.
The first is a viscosifier which is readily soluble in water at a temperature between about 40 and 100F and which becomes substantially insoluble in the treatment ~luid at the temperatures encountered under downhole conditions, commonly referred to as bottom hole cir-culating temperature (hereafter B.H.CAT.). The second component is a thickener capable of dispersion or solution in water which will impart sufficient viscosity to the water at B.H.C.T. to be encountered when the first component loses its viscosifying capabilities. A
third component, a dispersant, is employed to enhance the dispersibility of the first component and thereby to simplify and expedite mixing of the composition in the field to form the agueous treatment fluid. The components are combined in such amounts that when dispersed in water, together with an amount of weighting agent required to impart the desired viscosity to the fluid, the aqueous treatment fluid will attain a kinematic viscosity of greater than 0.1 and less than 7.5 centiPOise~g~llon at a temperature between 85 and pound 28,628-F -6-~577~7 --7=
More particularly, the lnvention resides in an aqueous trea~ment fluid which ~as a yield point of zero at a temperature be~ween 30 and 71C and ls compatible with cement slurries and drilling muds employed in the completion and drilling of subterranean boreholes, which trea~ment fluid comprises:
Component (A) A viscosifier which ls soluble in and increases the kinematic viscosi~y of water at temperatures between 4 and 38C and which becomes substantially i~oluble in said treatment fluid at a temperature be~ween 30 and 71C, Component (B) A thic~ener which is different ~han component ~ and soluble or dispersible in and increases the klnematic viscoslty of water at temperatures be~ween 4 and 71C;
Comp~nent (C) A dispersant which enhances the dispersibility of Compo~ent (A) in water;
Componen~ (D3 A weighting agent; and Component (E). Water;
wh~rei.~ said Componenks are present in amounts suffi-cie~t ~o impart a kinematic viscosity to said trea~ment 1uid, at a tempera~ure be~ween 30 and 71C, ~f greater than O.1 and less than 7.5 ce~tipolsd-qallon The inventio~ fu~ther resides In a ~ietho~ ^or injecting a fluid into a borehole containina a drilling mud, wherein the fluid i~ not compati~le with the m~d and wherein in~ection o~ said fluid is preceded by injection o a composition compatible with both th2 mud and the fluid, the improvement comprisinq: injecting a sufficient quantity o~ said 28,628-F -7-, . ~ . ,~
composltlon to separate said mud and said fluid, at an injection velocity which exceeds the critical velocity fer said composition in the borehole at the bottom hole circu~
lating temperature of said borehole, whexe the composltion comprises the aqueous treatment fluid of Claim 1.
By critical velocity, is meant the rate at which the aqueous treatment ~luid must b~ pumped to achieve turbulent flow for the ~ C.T.
Several ~erms which are used throughout in the description and explanation of the invention should be defined at this point. The term "viscosity" is used in several di~ferent contexts. When viscosity is merely referred to by itself, it is used in the lay sense to mean a property of thickness or viscousness which a fluid has. The term "apparent viscosity" is ~ quan-ti-fication of the thickne~s of a fluid and is expressed here in centi~oise units derived from a measurement at 300 RPM (~300) by use of a simple conversion factor.
The 300 RPM readings axe taken on a model 35 Fann VG
Vi~cometer with R1-Bl rotor/bob combination and a spring factor of one. The term "yield pointl' refers to an ~mpir1cally derived quantity calculated as the dif~erence between twice the 300 RPM reading and the 600 RPM reading for a fluid (expressed as 2~300 ~ ~600) The yield point is important in charac~erization of the fluid's behavior as either Newtonian or non-Newtonian.
A fluid having a yield point of zero at a given temperature exhibits Newtonian behavior at that temperature. The temperature at which the yield point of a fluid goes to zero is called its "txansition temperature". The density of a fluid as referred to herein is expressed in pounds per gallon and is, unless otherwise stated, .;
28,628-F -8 :`
.~
~5~
g measured at ~0F and represented by the term "P". The term "kinematic viscosity" refers to a property of a fluid calculated by dividiny the apparent viscosity of the fluid, expressed in centipoise, by the density of the fluid P, expressed in pounds per gallon. The term "pseudoplastic~' as used herein refers to the behavior of a fluid which has a yield point which is a positive number at a given temperature and whose apparent viscosity decreases with increased xates of shear. The transition temperature for a pseudoplastic material is the temperature at which it looses its pseudoplastic properties and assumes Newtonian behavior, i.e. the temperature at which its yield point goes to zero. Another property of various fluids that is described herein is fluid loss and it is determined according to API methods.
Throughout the specification, Component A, the viscosifier, is referred to as becoming substantially inso].uble in water at some temperature. By substantially insoluble is meant -that a fluid consisting of that Component A and water experiences a loss in apparent viscosity such that the apparent viscosity of the resultant ~luid is approximately two centipoise or less.
The temperature at which this occurs is approximately the transition temperature of that fluid and the fluid becomes essentially a Newtonian fluid since it is pxedominantly water. Throughout the specification, the aqueous treatment fluid of the invention is referred to as being "compatible" with cement slurries and drilling muds. By compatible is meant that when the aqueous treatment flui~ and cement slurry or mud are intimately mixed in about 50-50 ratios by volume, the apparent viscosity of the resulting mixture does not exceed the apparent viscosity of either of the components by more than about 20 percent.
28,628-F -9-The composition of the invention includes both a dry mixture comprising three or more components and aqueous treatment fluids derived from this dry mixture by combining with water. The first component, Component A is a viscosifier which is soluble in and increases ~he kinema~ic viscosity o~ water before being exposed to the sort of t mperatures which would be encountered downhole but which becomes suhstantially insoluble in water at such downhole temperatures. The second component, Component B is a thickener which is soluble or dispersible in water and increases its kinematic viscosity e~en at tempexatures encountered under downhole conditions. The third component, a dispersant, is included in the composition to enhance the dispersibility of the first component in water. It is desixable to smoothly and easily disperse Component A in water to achieve a complete solution within as a short a time as possible and avoid the prohlems created in field mixing which are caused if the first component forms insoluble lumps and gels upon introduction into water. When Component A is of such a nature that it contains a built-in dispersant or does no-t need one, then Component C may be omitted. In a preferred embodiment, a fourth component, a weighting agent, ls included with 2S the first three components before the mixture is dispersed in water to form an agueous treatment fluid. Any weighting agent not incompatible with the other components or with cement slurri~s or drilling muds may be employed for this purpose. In another preferred embodiment, an additional component, a nonionic surfactant, is added to the composition to enhance the compatibility of the resultant aqueous treatment fluid with oil-based drilling muds. This nonionic surfactant component will not be required in the instances where Component A is of such 28,628~F -10-7~
Wll--a character as to have inherent surfactant properties and thereby render the resultant aqueous treatment fluid compatible with such muds.
Component A is suitably selected from hydroxy~
alkylcelluloses which are generally nonionic in nature and whlch commonly have inherent surfactant properties due to their chemical nature. Such materials are hydroxyethylcellulose, hydroxypropylcellulose, hydroxy-butylcellulose, hydroxyethylmethylcellulose, hydroxy-propylmethylcellulose, and hydroxybu~ylmethylcellulose.Hydroxyalkylcelluloses in which ~he hydroxyalkyl groups are hydroxypropyl or hydroxybutyl are preferred for use in the invention. These materials come in a wide variety of molecular weights and in varying degrees of hydroxyalkyl and methoxyl substitution on the hydroxyl ~roups pendant on the backbone of the cellulose chains.
Depending on the molecular weight of the hydroxyalkyl~
cellulose employed, greater or lesser quantities of the matexial will be required to impart the desired thickness -to the resulting aqueous treatment fluid, with molecular weight and amount required to impart a given viscosity being inversely proportional.
The temperature at which a hydroxyalkylcellulose becomes substantially insoluble in water may vary widely and dep~nds primaxily on the degree and type of hydroxyal.kyl substitution and the degree of methoxy substitution on the cellulose backbone. Hydroxyalkyl substituents are more hydrophobic in -the increasing order hydroxyethyl, hydroxypropyl, and hydroxybutyl.
Generally, the higher the degree of hydrophobic substi-tution, the lower will be the temperature at which the material becomes subs-tantially insoluble in water, this 28,628-F -11~
temperature being commonly known as the "gel temperature".
The gel temperature oE a given material is also affected by the presence of other solutes ln a~ueous solution.
Commonly, inorganic salts such as sodium chloride and potassium chlorlde serve to depress the gel temperature of a given hydroxyalkylcellulose solution and the viscos~fying effect of a given amount of Component ~
may also be decreased in a corresponding fashionO The gel temperature of a given aqueous solution of a hydroxy-alkylcellulose may be raised and the viscosifyingeffect of a given amount of the hydroxyalkylcellulose enhanced by the presence of various surfac-tants or wetting agents such as the type of dispersants employed as Component C, glycols or glycol ethers and other r~onionic surfactants.
Consequenkly, routine experimentation may be employed with the knowledge of the foregoing teachings to select an appropriate viscosifier in appropriate amounts together with sufficient quantities of a dispersant or a salt to raise or lower the corresponding gel temperature of the resultant solution, respectively.
In this fashion, an aqueous txeatment fluid with a wide range of gel temperatures may be designed as appropriate for the downhole temperatures to be encountered in the intended use. Manufacturer's literature for most hydroxy-alkylcellulose products is available describing the respective gel temperature of these products as well as the effect of various solutes, such as salts and dispersant, on the gel temperature and the viscosity of their resultant aqueous solutions.
Because of the ease of dispersion under field conditions and because they possess gel -temperatures 28,628-F -12-7~7~7 within the range commonly encountered under downhole condi~ions, hydroxypropylcelluloses and hydroxypropyl-methylcelluloses are preferred in the instant invention.
Most preferred are hydroxypropylcelluloses, embodiments of which will ~e described more fully herein. For higher downhole temperatures, however, hydroxyethyl-celluloses which generally have higher gel temperatures would be useable.
Component B, a thickener, is dispersible or soluble in water and increases the kinema~ic viscosity of water at the temperatures encountered under downhole conditions, i.e. it does not have a gel temperature in the range that Component A does and therefore can maintain the aqueous treatment fluid in a somewhat thickened state under downhole conditions. For this purpose, various polymers may be employed, including some of those useful at highex temperatures as Component A i~ the temperature to which the aqueous treatment fluid will be exposed downhole is less than the gel temperature o~ Component B. In such a situation, a material with a gel temperature within the range of downhole conditions will be chosen as Component A
instead. Representative materials are hydroxyalkyl-celluloses having gel temperatures generally in excess of 160F, for example some hydroxyethylcelluloses and some hydroxypropylmethylcelluloses and carboxymethyl cellulose. Such polymers are benefically combined with a water-swellable extender such as a water-swellable clay, which will impart added thickening to the aqueous treatment fluid but which will not be as sensitive to temperature as some of the natural and synthetic higher polymers are. Of the types of water-swellable clays, attapulgites and bentonites, especially sodium bentonites, 28,628-F -13-are particularly preferred. When employing a mixture of polymer and a water-swellable extender, it is preferable to use abcut equal weight proportions of the two components or ratios of extender to polymer of about two or three to one.
As Component C, practically any water soluble dispersant may be employed. Anionic and cationic dispersants such as sodium dodecylbenzenesulfonate, sodium alkylsulfonate, fatty alkyl benzyl ammonium chlorides, diethanolamine or triethanolamine fatty sulfates and the like serve such purpose. Preferably, the disperant is selected from sulfonated hydrocarbon compounds and their salts and more preferably from sulfonated aromatic hydrocarbons and their salts.
Materials such as sodium alkylbenzene sulfonates and sodium polynaphthalene sulfonates serve well as Com-ponent C. Generally lignins and their sulfonated derivatives as well as sugar derivatives are preferably avoided for use as a dispersant in this application since they tend to retard the setting of cement slurries.
Where retardation of cement setting is not detrimental, they may also be employed.
As weighting agent, any commonly used weighting - agent for drilling muds and cement slurries may generally be employed in the instant invention. Material such as carbonates of calcium may be suitable in instances where calicum ions are not incompatible with Arilling muds to be encountered, and iron carbonate, various iron oxides such as hematite or ilmenite, and barium sulfate (commonly known as barite), are common agents that may be employed. Because of its wide use and readily availability, the use of baxite as a weighting 28,628-F -14--15~
agent for the aqueous treatment fluid is preferred, especially when densities of between 9 and 18 pounds per gallon are desired. When preparing aqueous treat-ment fluids with densities in excess of 18 pounds per gallon, it is preferred to incorporate incre-mental amounts of a denser agent such as ilmenite in a treatment fluid which has already been weighted to about 18 pounds per gallon with barite.
In many instances where a hydroxyalkylcellulose is employed in Component A, the resulant aqueous treatment fluid will have reasonable compatibility with oil based drilling muds, since such cellulosics commonly have the attribute of built-in surfactancy. ~owever, in instances where empirical mixing tests indicate unacceptable thickening of mixtures of the aqueous txeatment fluid and an oil-based mud, minor amoun-ts of a nonionic surfactant may be incorporated in the invention compo-sition and the resulking aqueous treat~ent fluids.
Preferably, employed is a nonionic, alkoxylated alcohol, more preferably an alkoxylated-alkanol or -alkylphenol and most prefera~ly an ethyoxylated derivative of such an alcohol.
Because of th~ wide variety of conditions under which the invention composition and resul~ant aqueous treatment fluid will be employed, it is useful to define the relative amounts of the components to be employed in terms of empirical tests which relate to the characteristic properties of the aqueous treatment fluid which are desired and are defined herein. For example, it is preferred that the aqueous treatment fluid exhibit a kinematic viscosity of less than 7.5, more preferably less than 5.5, and most preferably less 23,628-F -15-~16~
than 4 centipoise-gallons/pounds and greater than 0.1, more preferably greater than 0.3 and most preferably greater than 0.5 centipoise-gallons/pounds, at a temperature between about 85 and about 160F. Since it is also desirable that the treatment fluid exhibit Newtonian properties within that temperature range, i.e. have a yield point of zero in that range, one may select the appropriate amounts of Component A, B, and C
to combine with a given quantity of water to give a fluid having the desired initial thickness as well as a viscosity reduction at the downhole temperature under which the treatment fluid will be employed. Generally, the total amount of Components A, B and C r~quired to attain the desired properties will be l to lO percent based upon the weight of water employed to prepare -the aqeuous treatment fluid. At this level, an aqueous fluid with a density of about 8.5 pounds per gallon will result. To such a fluid, the appropriate amount o~ weighting agent required to attain the final desired density may easil~ be calculated or determined empiri-cally by adding weighting agent in increments and measuring the resultant densities.
In a preferred mode, the relative amounts of the basic components will be one to fifteen parts Component A, 5 to 40 parts, Component B, l to 25 parts, Component C and 0 to 20 parts nonionic surfactant, all parts by weight. In preparing a preferred aqueous treatment fluid, Component A comprises 0.1 to 1.5 percent, Component B comprises 0.5 to 4 percent, Component C comprises 0.1 to 2.5 percent, a nonionic surfactant comprises 0 to 2 percent and water comprises 90 -to 98 percent of the combined weight of these com-ponents o the treatment fluid. When weighting agent 28,628-F -16-5~7~
-17~
is employed it is preferably added in an amoun~ ranging from 1.5 percen~ to 150 percent of the unweighted aqueous treatment fluid. Operable ranges can be easily determined by rou~ine experimentation based on these general ranges and the information contained hereafter in the speciic embodiments of the invention.
The composition of the invention may also contain other common treatment fluid ingredients such as fluid loss contxol additives, dyes, antifoaming agents where necessary and the like, employed in their usual quantities, of course the addi~ion of su~h other additives should be avoided if it will detrimentally affect the basic desired properties of the aqueous treatment fluid or if they will interact detrimentally with the drilling muds or cement slurries.
The aqueous treatment fluid of the invention is beneficially employed as a compatible fluid in a borehole between a drilling mud and a second fluid which is to be injected to displace the drilling mud ~0 from the borehole. Commonly, this second 1uid is a cement slurry. In this method, it is recommended that a sufficient amount of the aqueous treatment fluid be employed to provide at least five and more preferably at least ten minutes contact time with the walls of the borehole or annulus through which the treatment fluid is to be pumped at whatever the desired pump rate.
Since the volume of the borehole or annulus through which the aqueous treatment fluid will be pumped is known as is the desired pump rate, the volume of aqueous treatm~nt fluid to be employed in order to attain such contact time is readily calculated.
28,628-F -17-The preferred pumping rate of the treatment fluid in such an application is less ~han 16 barrels per minute, more preferably less than 12 barrels per minute and most preferably less than 8 barrels per minute and is preferably greater than l, more preferably greater than 2 and most preferably greater than 3 barrels per minute. The aqueous treatment fluid is employed in a borehole having a bottom hole circulatlng temperature preferably below 350F, more preferably below 250F and most prefercibly below 200F and is preferably employed at a minimum B.H.C.T. of 80F, more preferably greater than 100F and most preferably greater than 125F. In one preerred mode, it is employed in a borehole with a B.H.C.T. between 125 and 145F and in another preferred embodiment is employed in a borehole with a B.H.C.T. between 150 and 250F.
Many of the wells in which a good cement bond is essential are found offshore. Another preferred embodiment of the invention employs an aqueous treatment 1uid which further comprises sodium chloride in an amount o~ 1 to 18 percent, more preferably 1 to 3 percent, based upon the weight of water. As noted before, the presence of sodium chloride or ano-ther salt such as potassium chloride serves to depress the gel temperature of Component A of the invention composition.
The foregoing will generally serve to describe the invention to the reader and enable him to practice the invention within the guidelines outlined above.
The following exemplary em~odiments will further describe the invention and prepare the reader to practice same.
28,628 F 18-A composition of the invention is prepared by dry blending about 11.7 parts of Klucel~ J hydxoxypropyl-cellulose, sold by Hercules, Inc.; about 8.9 parts by weight 7L carboxymethylcellulose also sold by Hercules, Inc.;
about ~3.~ parts of a bentonite which meets the specifi~
cation set forth API standard lOA; and about 6.1 parts Lomar~
D surfactant, a sodium polynapthalene sulfonate sold by Nopco Chemical, (all parts by weight herein unless otherwise designated). ~s can be seen by re~erence to the preceding 10 body of this specification, the first component corresponds to component A of the inven~ion, the combination of the second and third components correspond to component B of the invention and the fourth component corresponds to Component C of the in~ention. Additionally, a small quantity o a dye may be added to the composi~ion to aid in identification of the returns from a wellbore if desired. A blend of the foregoing components is hereafter referred to as Blend A and is employed in the following e~amples to prepare an aqueous treatment fluid by adding 16.3 pounds of Blend A to 41 gallons of fresh water to make one barrel of a~ueous treatment fluid A having a density o~ 8.6 pounds per gallon (hereafter ppg). To prepare an aqueous treatment 1uid of greater density, a ~uantity o~ weighting agent is either pre~lended with the dry Blend A or added after Blend ~ is dispersed into the water. The amount of weighting agent to be employed can be determined from the following equation X = (42 P - 362) /(1 - VE) where X represents pounds of weighting agent to be added per barrel of aqueous treatment fluid, V represents the absolute volume of the weighting agent in gallons per pound and P represents the density of the treatment fluid desired in pounds per gallon. For barite, which is employed to weight the a~ueous treatment fluids in the following Registered Trade Mark 28,628-F -19-~5~
~20-examples, V = 0.278. Generally the aqueous treatment fluid should be designed to have a greaier density than the drilling mud which it will be displacing but less d~nsity than the fluid which is following it, e.g. the cement slurry. Preferably, it should be at least about 0.2 ppg heavier than the drilling mud and more preferably at least l ppg heavier than the drilling mud.
Example l ~ Mud Com~atibility A sample of aqueous treatment Fluid A is prepared in the manner described above and weighted to a given density with the appropriate quantity of barite.
Samples of synthetic drilling muds are prepared and then mixed in various proportions with aqueous treatment Fluid A weighted with barite to a density approximately l ppg greater than that of the mud. The respectiv~
apparent viscosity (expressed as 0300 reading) is measured on the model 35 Fann VG viscometer, as pre-viously described at a 300 rpm reAding. Fluid B is the same composition as Fluid A except that l percent (based on weight of water, BWOW) of a nonionic sur-actant, a 10 mole adduct of ethylene oxide to di(sec~
butyl) phenol is added for better compatibility with based mud.
The drilling mud samples are prepared by thoroughly mixing the dry components with fresh water in a Waring blender then permitted to hydrate for about a 24 hour period. The compositions are:
Mud A:
Density - 10 ppg 500 parts wa-ter 20 parts Wyoming bentonite 125 parts barite 28,628-F-20-~85~
Mud B:
Density - 14 ppg 500 parts water 30 parts Wyoming bentonite
The invention pertains to a composition which when intimately mixed with water forms an aqueous treatment fluid suitable for use as a well completion or spacer fluid in the drilling of oil and gas wells or other boreholes in subterranean formations. It also relates to a method of using such an aqueous treatment fluld as a spacer composition, particularly in the context of cemerlting casing in a wellbore.
Rotary drilling techniques are commonly used for drilling wells in the earth thrcugh subterranean formations of sandstone, shale, limestone, etc. In such rotary drilling, a drilling fluid or "drilling mud" is circulated between the surface of the earth and the bottom of the well. Drilling muds which are commonly used include water-based muds comprising both clay and polymer containing muds, oil-based muds and emulsions.
Drilling muds serve many useful purposes including the removal of earth and rock cuttings from the well, control of foxmation pressures, and cooling and lubri-cation of the drill bit which is used in drilling thewell. However, there are also certain detrimental characteristics associated with drilling muds. Among 28,628-F -1-~L~8~777 the problems associated with drilling muds is that drilllng muds tend to flow from the well into exposed permeable formatlons with ~he result that mud solids are filtered out on the wall of the well and a filter cake is formed. Even thin filter cakes are detrimental in the completion of wells because they sometimes interfere with the formation of a good cement bond between the wall of the wellbore and the casing posi-tioned in this wellbore. AlSo, drilling muds fre-quently contain components which are incompatible witha fluid which one may desire to inject into a well containing such mud. For example, it has long been recognized that if certain cement slurries containing free polyvalent metal cations, especially calcium, are brought into contact with muds containing clay or certain polymers, a very viscous and detrimental plug can form in the vicinity of the mud-cement interface.
The problems created by such a highly viscous mud-cement interface are well known in the well cementing art.
Another example of mud-cement incompatibility is that lignins, which are frequently used as dispersants in high density muds, can cause excessive retardation in cements if cement becomes comingled with the mud.
Consequently, various techniques have been devised for the removal of drilling muds from a borehole, particularly in the contex-t of injecting a fluid into the borehole which is incompatible with the mud, more specifically in the context of cementing. A common techni~ue is to employ a "spacer" or a "chemical wash".
Although it not always clear in the literature whether fluid is a spacer or a chemical wash, a spacer is generally characterized as a thickened composition which functions primarily as a fluid piston in dis-placing the mud. Spacers frequently contain appreciable 28,628-F -2---3~
quantities of weighting agents to impart a desired density ~o the spacer fluid. Chemical washes, on the other hand, are generally thin fluids which are effective principally as ~he result of turbulance, dilution, and surfactant action on the mud and mud filter cake.
Chemical washes often contain solids to act as an abrasive but the solids content is significantly lower than in spacers because the washes are generally too thin to have good solids carrying capacity.
The art of preparing and using spacers and chemical washes is discussed in detail in U.S. Patent 4,083,407. Of particular interest is U.S. Patent 3,291,211, Savins et al. which describes a process for removing mudcake from the wall of a borehole and then cementing the casing in such a wellbore by using a fluid said to have "viscoelastic" properties as a spacer to displace a mudcake from the annulus. The vi.scoelastic fluid is said to be prepared from an oil--miscible solvent for use with an oil-based drilling mud ~0 or from water or water-miscible solvent in the case of use with a water-based drilling mud. Viscoelastic properties are imparted to the spacer fluids by the addition of various solutes to the respective solvents.
Among the solutes mentioned are high molecular weight cellulose derivatives such as carboxymethylcellulose (CMC) and hydxoxyethylcellulose (HEC), polyethylene oxides, sulfonated polystyrenes, polyacrylamides and partially hydrolyzed polyacrylamides, natural gums, fatty acid soaps, etc. Savins prefers that his visco-elastic fluids be such that a normal stress of at least2000 dynes per square centimeter is developed in a rotating viscometer.
28,628-F -3-~4~
In U.SO Patent 4,141,843, Watson discloses a nondamaging spacer fluid comprising weighting agents dispersed in water, a polymer viscosifier and several other components. The spacer is said to be stable over a temperature range of about 32-300F for extended periods of time. The fluids described by Watson employ as preferred viscosifiers water soluble polysaccharides, especially hydroxyalkylcelluloses having two to three carbon atoms in the hydroxyalkyl groups. The spacer fluids prepared by Watson are said to be non Newtonian in character, i.e. they have yield points which are not equal to zero.
In a publication entitl~d "Applied Engineered Cementing'l (1969) by Byron Jackson, Inc., pages 54-55, a "cementing preflush", or spacer as the term is used herein, designated Mud-Sweep is described as a high viscosity, aqueous solution having a density which can be adjusted from 8.6 to as high as 1~ pounds per gallon.
Th~t spacer is said to operate on a "viscous sweep"
principle to accomplish maximum mud removal regardless oE the flo~ rate. It is said not to be necessary to attain turbulent flow to achieve excellent mud removal.
The composition of the spacer is not disclosed, however it is stated to be highly viscous yet thixotropic, to contain de-oiling chemicals that tend to preferentially water wet the casing and wellbore and to also contain additives that "flocculate clay-base drilling muds, forming a viscous interface that aids in sweeping mud from the annulus". Obviously, that spacer is incompatible with many drilling fluids.
In U.S. Patent 4,083,407 CMC and HEC are employed by Griffin et al. as fluid loss control additives.
28,628-F -4-The spacer itself is thickened with a polyvalen~ metal siiicate.
The present invention has both the properties of a spacer and a chemical wash. It comprises a composi-tion especially designed to be soluble ox dispersiblein water providing a resultant aqueous treatment 1uid of sufficient thickness or l'viscosity" to permit sus-pension thereof of a quantity of weighting agent suf-ficient to impart a desired density to the thus weighted aqueous treatment fluid. The treatment fluid is prepared wi-th suitabl~ viscosifiers and thickeners such that a thick fluid is a~tained that is sufficiently viscous to suspend the desired weighting agents upon mixing, blending, handling and transportation of the so--weighked fluid at temperatures encountered during field operations and yet the aqueous treatmen~ fluid will experience a sufficient viscosity loss under downhole conditions to attain a kinematic viscosity which permi-ts the treatment fluid to go into turbulent ~low at reasonable pumping rates, e.g. less than 16, preerably less than 12 and more preferably less than 8 barrels per minute.
Stated another way, the treatment fluid is designed to be a pseudoplastic fluid at temperatures of mixing and handling yet become a Newtonian fluid at the temperatures encountered under downhole conditions when the fluid is pumped in the annulus between a borehole and a casing or some other void space in a subterranean borehole. Since the fluid is designed to go into turbulent flow, the tuxbulence generally will be suf-ficient to suspend the solid particulate materials which are commonly employed as weighting agents.
However, it is preferable that the treatment fluid 28,628-F -5---6~
maintain sufficient viscosity under downhole conditions to suspend such particulate material und~r static or plug or laminar flow conditions. Consequently, it is preferred that under downhole temperature conditions a kinematic viscosity be maintained equal to 15 centpp _se, where P is defined as the density of the treatment fluid in pounds per gallon. This is particularly desirable if the possibility of pump s~oppage or break-down is present.
In the invention, the preferred composition to be used in obtaining such an aqueous treatment fluid is prepared by combining at least three components.
The first is a viscosifier which is readily soluble in water at a temperature between about 40 and 100F and which becomes substantially insoluble in the treatment ~luid at the temperatures encountered under downhole conditions, commonly referred to as bottom hole cir-culating temperature (hereafter B.H.CAT.). The second component is a thickener capable of dispersion or solution in water which will impart sufficient viscosity to the water at B.H.C.T. to be encountered when the first component loses its viscosifying capabilities. A
third component, a dispersant, is employed to enhance the dispersibility of the first component and thereby to simplify and expedite mixing of the composition in the field to form the agueous treatment fluid. The components are combined in such amounts that when dispersed in water, together with an amount of weighting agent required to impart the desired viscosity to the fluid, the aqueous treatment fluid will attain a kinematic viscosity of greater than 0.1 and less than 7.5 centiPOise~g~llon at a temperature between 85 and pound 28,628-F -6-~577~7 --7=
More particularly, the lnvention resides in an aqueous trea~ment fluid which ~as a yield point of zero at a temperature be~ween 30 and 71C and ls compatible with cement slurries and drilling muds employed in the completion and drilling of subterranean boreholes, which trea~ment fluid comprises:
Component (A) A viscosifier which ls soluble in and increases the kinematic viscosi~y of water at temperatures between 4 and 38C and which becomes substantially i~oluble in said treatment fluid at a temperature be~ween 30 and 71C, Component (B) A thic~ener which is different ~han component ~ and soluble or dispersible in and increases the klnematic viscoslty of water at temperatures be~ween 4 and 71C;
Comp~nent (C) A dispersant which enhances the dispersibility of Compo~ent (A) in water;
Componen~ (D3 A weighting agent; and Component (E). Water;
wh~rei.~ said Componenks are present in amounts suffi-cie~t ~o impart a kinematic viscosity to said trea~ment 1uid, at a tempera~ure be~ween 30 and 71C, ~f greater than O.1 and less than 7.5 ce~tipolsd-qallon The inventio~ fu~ther resides In a ~ietho~ ^or injecting a fluid into a borehole containina a drilling mud, wherein the fluid i~ not compati~le with the m~d and wherein in~ection o~ said fluid is preceded by injection o a composition compatible with both th2 mud and the fluid, the improvement comprisinq: injecting a sufficient quantity o~ said 28,628-F -7-, . ~ . ,~
composltlon to separate said mud and said fluid, at an injection velocity which exceeds the critical velocity fer said composition in the borehole at the bottom hole circu~
lating temperature of said borehole, whexe the composltion comprises the aqueous treatment fluid of Claim 1.
By critical velocity, is meant the rate at which the aqueous treatment ~luid must b~ pumped to achieve turbulent flow for the ~ C.T.
Several ~erms which are used throughout in the description and explanation of the invention should be defined at this point. The term "viscosity" is used in several di~ferent contexts. When viscosity is merely referred to by itself, it is used in the lay sense to mean a property of thickness or viscousness which a fluid has. The term "apparent viscosity" is ~ quan-ti-fication of the thickne~s of a fluid and is expressed here in centi~oise units derived from a measurement at 300 RPM (~300) by use of a simple conversion factor.
The 300 RPM readings axe taken on a model 35 Fann VG
Vi~cometer with R1-Bl rotor/bob combination and a spring factor of one. The term "yield pointl' refers to an ~mpir1cally derived quantity calculated as the dif~erence between twice the 300 RPM reading and the 600 RPM reading for a fluid (expressed as 2~300 ~ ~600) The yield point is important in charac~erization of the fluid's behavior as either Newtonian or non-Newtonian.
A fluid having a yield point of zero at a given temperature exhibits Newtonian behavior at that temperature. The temperature at which the yield point of a fluid goes to zero is called its "txansition temperature". The density of a fluid as referred to herein is expressed in pounds per gallon and is, unless otherwise stated, .;
28,628-F -8 :`
.~
~5~
g measured at ~0F and represented by the term "P". The term "kinematic viscosity" refers to a property of a fluid calculated by dividiny the apparent viscosity of the fluid, expressed in centipoise, by the density of the fluid P, expressed in pounds per gallon. The term "pseudoplastic~' as used herein refers to the behavior of a fluid which has a yield point which is a positive number at a given temperature and whose apparent viscosity decreases with increased xates of shear. The transition temperature for a pseudoplastic material is the temperature at which it looses its pseudoplastic properties and assumes Newtonian behavior, i.e. the temperature at which its yield point goes to zero. Another property of various fluids that is described herein is fluid loss and it is determined according to API methods.
Throughout the specification, Component A, the viscosifier, is referred to as becoming substantially inso].uble in water at some temperature. By substantially insoluble is meant -that a fluid consisting of that Component A and water experiences a loss in apparent viscosity such that the apparent viscosity of the resultant ~luid is approximately two centipoise or less.
The temperature at which this occurs is approximately the transition temperature of that fluid and the fluid becomes essentially a Newtonian fluid since it is pxedominantly water. Throughout the specification, the aqueous treatment fluid of the invention is referred to as being "compatible" with cement slurries and drilling muds. By compatible is meant that when the aqueous treatment flui~ and cement slurry or mud are intimately mixed in about 50-50 ratios by volume, the apparent viscosity of the resulting mixture does not exceed the apparent viscosity of either of the components by more than about 20 percent.
28,628-F -9-The composition of the invention includes both a dry mixture comprising three or more components and aqueous treatment fluids derived from this dry mixture by combining with water. The first component, Component A is a viscosifier which is soluble in and increases ~he kinema~ic viscosity o~ water before being exposed to the sort of t mperatures which would be encountered downhole but which becomes suhstantially insoluble in water at such downhole temperatures. The second component, Component B is a thickener which is soluble or dispersible in water and increases its kinematic viscosity e~en at tempexatures encountered under downhole conditions. The third component, a dispersant, is included in the composition to enhance the dispersibility of the first component in water. It is desixable to smoothly and easily disperse Component A in water to achieve a complete solution within as a short a time as possible and avoid the prohlems created in field mixing which are caused if the first component forms insoluble lumps and gels upon introduction into water. When Component A is of such a nature that it contains a built-in dispersant or does no-t need one, then Component C may be omitted. In a preferred embodiment, a fourth component, a weighting agent, ls included with 2S the first three components before the mixture is dispersed in water to form an agueous treatment fluid. Any weighting agent not incompatible with the other components or with cement slurri~s or drilling muds may be employed for this purpose. In another preferred embodiment, an additional component, a nonionic surfactant, is added to the composition to enhance the compatibility of the resultant aqueous treatment fluid with oil-based drilling muds. This nonionic surfactant component will not be required in the instances where Component A is of such 28,628~F -10-7~
Wll--a character as to have inherent surfactant properties and thereby render the resultant aqueous treatment fluid compatible with such muds.
Component A is suitably selected from hydroxy~
alkylcelluloses which are generally nonionic in nature and whlch commonly have inherent surfactant properties due to their chemical nature. Such materials are hydroxyethylcellulose, hydroxypropylcellulose, hydroxy-butylcellulose, hydroxyethylmethylcellulose, hydroxy-propylmethylcellulose, and hydroxybu~ylmethylcellulose.Hydroxyalkylcelluloses in which ~he hydroxyalkyl groups are hydroxypropyl or hydroxybutyl are preferred for use in the invention. These materials come in a wide variety of molecular weights and in varying degrees of hydroxyalkyl and methoxyl substitution on the hydroxyl ~roups pendant on the backbone of the cellulose chains.
Depending on the molecular weight of the hydroxyalkyl~
cellulose employed, greater or lesser quantities of the matexial will be required to impart the desired thickness -to the resulting aqueous treatment fluid, with molecular weight and amount required to impart a given viscosity being inversely proportional.
The temperature at which a hydroxyalkylcellulose becomes substantially insoluble in water may vary widely and dep~nds primaxily on the degree and type of hydroxyal.kyl substitution and the degree of methoxy substitution on the cellulose backbone. Hydroxyalkyl substituents are more hydrophobic in -the increasing order hydroxyethyl, hydroxypropyl, and hydroxybutyl.
Generally, the higher the degree of hydrophobic substi-tution, the lower will be the temperature at which the material becomes subs-tantially insoluble in water, this 28,628-F -11~
temperature being commonly known as the "gel temperature".
The gel temperature oE a given material is also affected by the presence of other solutes ln a~ueous solution.
Commonly, inorganic salts such as sodium chloride and potassium chlorlde serve to depress the gel temperature of a given hydroxyalkylcellulose solution and the viscos~fying effect of a given amount of Component ~
may also be decreased in a corresponding fashionO The gel temperature of a given aqueous solution of a hydroxy-alkylcellulose may be raised and the viscosifyingeffect of a given amount of the hydroxyalkylcellulose enhanced by the presence of various surfac-tants or wetting agents such as the type of dispersants employed as Component C, glycols or glycol ethers and other r~onionic surfactants.
Consequenkly, routine experimentation may be employed with the knowledge of the foregoing teachings to select an appropriate viscosifier in appropriate amounts together with sufficient quantities of a dispersant or a salt to raise or lower the corresponding gel temperature of the resultant solution, respectively.
In this fashion, an aqueous txeatment fluid with a wide range of gel temperatures may be designed as appropriate for the downhole temperatures to be encountered in the intended use. Manufacturer's literature for most hydroxy-alkylcellulose products is available describing the respective gel temperature of these products as well as the effect of various solutes, such as salts and dispersant, on the gel temperature and the viscosity of their resultant aqueous solutions.
Because of the ease of dispersion under field conditions and because they possess gel -temperatures 28,628-F -12-7~7~7 within the range commonly encountered under downhole condi~ions, hydroxypropylcelluloses and hydroxypropyl-methylcelluloses are preferred in the instant invention.
Most preferred are hydroxypropylcelluloses, embodiments of which will ~e described more fully herein. For higher downhole temperatures, however, hydroxyethyl-celluloses which generally have higher gel temperatures would be useable.
Component B, a thickener, is dispersible or soluble in water and increases the kinema~ic viscosity of water at the temperatures encountered under downhole conditions, i.e. it does not have a gel temperature in the range that Component A does and therefore can maintain the aqueous treatment fluid in a somewhat thickened state under downhole conditions. For this purpose, various polymers may be employed, including some of those useful at highex temperatures as Component A i~ the temperature to which the aqueous treatment fluid will be exposed downhole is less than the gel temperature o~ Component B. In such a situation, a material with a gel temperature within the range of downhole conditions will be chosen as Component A
instead. Representative materials are hydroxyalkyl-celluloses having gel temperatures generally in excess of 160F, for example some hydroxyethylcelluloses and some hydroxypropylmethylcelluloses and carboxymethyl cellulose. Such polymers are benefically combined with a water-swellable extender such as a water-swellable clay, which will impart added thickening to the aqueous treatment fluid but which will not be as sensitive to temperature as some of the natural and synthetic higher polymers are. Of the types of water-swellable clays, attapulgites and bentonites, especially sodium bentonites, 28,628-F -13-are particularly preferred. When employing a mixture of polymer and a water-swellable extender, it is preferable to use abcut equal weight proportions of the two components or ratios of extender to polymer of about two or three to one.
As Component C, practically any water soluble dispersant may be employed. Anionic and cationic dispersants such as sodium dodecylbenzenesulfonate, sodium alkylsulfonate, fatty alkyl benzyl ammonium chlorides, diethanolamine or triethanolamine fatty sulfates and the like serve such purpose. Preferably, the disperant is selected from sulfonated hydrocarbon compounds and their salts and more preferably from sulfonated aromatic hydrocarbons and their salts.
Materials such as sodium alkylbenzene sulfonates and sodium polynaphthalene sulfonates serve well as Com-ponent C. Generally lignins and their sulfonated derivatives as well as sugar derivatives are preferably avoided for use as a dispersant in this application since they tend to retard the setting of cement slurries.
Where retardation of cement setting is not detrimental, they may also be employed.
As weighting agent, any commonly used weighting - agent for drilling muds and cement slurries may generally be employed in the instant invention. Material such as carbonates of calcium may be suitable in instances where calicum ions are not incompatible with Arilling muds to be encountered, and iron carbonate, various iron oxides such as hematite or ilmenite, and barium sulfate (commonly known as barite), are common agents that may be employed. Because of its wide use and readily availability, the use of baxite as a weighting 28,628-F -14--15~
agent for the aqueous treatment fluid is preferred, especially when densities of between 9 and 18 pounds per gallon are desired. When preparing aqueous treat-ment fluids with densities in excess of 18 pounds per gallon, it is preferred to incorporate incre-mental amounts of a denser agent such as ilmenite in a treatment fluid which has already been weighted to about 18 pounds per gallon with barite.
In many instances where a hydroxyalkylcellulose is employed in Component A, the resulant aqueous treatment fluid will have reasonable compatibility with oil based drilling muds, since such cellulosics commonly have the attribute of built-in surfactancy. ~owever, in instances where empirical mixing tests indicate unacceptable thickening of mixtures of the aqueous txeatment fluid and an oil-based mud, minor amoun-ts of a nonionic surfactant may be incorporated in the invention compo-sition and the resulking aqueous treat~ent fluids.
Preferably, employed is a nonionic, alkoxylated alcohol, more preferably an alkoxylated-alkanol or -alkylphenol and most prefera~ly an ethyoxylated derivative of such an alcohol.
Because of th~ wide variety of conditions under which the invention composition and resul~ant aqueous treatment fluid will be employed, it is useful to define the relative amounts of the components to be employed in terms of empirical tests which relate to the characteristic properties of the aqueous treatment fluid which are desired and are defined herein. For example, it is preferred that the aqueous treatment fluid exhibit a kinematic viscosity of less than 7.5, more preferably less than 5.5, and most preferably less 23,628-F -15-~16~
than 4 centipoise-gallons/pounds and greater than 0.1, more preferably greater than 0.3 and most preferably greater than 0.5 centipoise-gallons/pounds, at a temperature between about 85 and about 160F. Since it is also desirable that the treatment fluid exhibit Newtonian properties within that temperature range, i.e. have a yield point of zero in that range, one may select the appropriate amounts of Component A, B, and C
to combine with a given quantity of water to give a fluid having the desired initial thickness as well as a viscosity reduction at the downhole temperature under which the treatment fluid will be employed. Generally, the total amount of Components A, B and C r~quired to attain the desired properties will be l to lO percent based upon the weight of water employed to prepare -the aqeuous treatment fluid. At this level, an aqueous fluid with a density of about 8.5 pounds per gallon will result. To such a fluid, the appropriate amount o~ weighting agent required to attain the final desired density may easil~ be calculated or determined empiri-cally by adding weighting agent in increments and measuring the resultant densities.
In a preferred mode, the relative amounts of the basic components will be one to fifteen parts Component A, 5 to 40 parts, Component B, l to 25 parts, Component C and 0 to 20 parts nonionic surfactant, all parts by weight. In preparing a preferred aqueous treatment fluid, Component A comprises 0.1 to 1.5 percent, Component B comprises 0.5 to 4 percent, Component C comprises 0.1 to 2.5 percent, a nonionic surfactant comprises 0 to 2 percent and water comprises 90 -to 98 percent of the combined weight of these com-ponents o the treatment fluid. When weighting agent 28,628-F -16-5~7~
-17~
is employed it is preferably added in an amoun~ ranging from 1.5 percen~ to 150 percent of the unweighted aqueous treatment fluid. Operable ranges can be easily determined by rou~ine experimentation based on these general ranges and the information contained hereafter in the speciic embodiments of the invention.
The composition of the invention may also contain other common treatment fluid ingredients such as fluid loss contxol additives, dyes, antifoaming agents where necessary and the like, employed in their usual quantities, of course the addi~ion of su~h other additives should be avoided if it will detrimentally affect the basic desired properties of the aqueous treatment fluid or if they will interact detrimentally with the drilling muds or cement slurries.
The aqueous treatment fluid of the invention is beneficially employed as a compatible fluid in a borehole between a drilling mud and a second fluid which is to be injected to displace the drilling mud ~0 from the borehole. Commonly, this second 1uid is a cement slurry. In this method, it is recommended that a sufficient amount of the aqueous treatment fluid be employed to provide at least five and more preferably at least ten minutes contact time with the walls of the borehole or annulus through which the treatment fluid is to be pumped at whatever the desired pump rate.
Since the volume of the borehole or annulus through which the aqueous treatment fluid will be pumped is known as is the desired pump rate, the volume of aqueous treatm~nt fluid to be employed in order to attain such contact time is readily calculated.
28,628-F -17-The preferred pumping rate of the treatment fluid in such an application is less ~han 16 barrels per minute, more preferably less than 12 barrels per minute and most preferably less than 8 barrels per minute and is preferably greater than l, more preferably greater than 2 and most preferably greater than 3 barrels per minute. The aqueous treatment fluid is employed in a borehole having a bottom hole circulatlng temperature preferably below 350F, more preferably below 250F and most prefercibly below 200F and is preferably employed at a minimum B.H.C.T. of 80F, more preferably greater than 100F and most preferably greater than 125F. In one preerred mode, it is employed in a borehole with a B.H.C.T. between 125 and 145F and in another preferred embodiment is employed in a borehole with a B.H.C.T. between 150 and 250F.
Many of the wells in which a good cement bond is essential are found offshore. Another preferred embodiment of the invention employs an aqueous treatment 1uid which further comprises sodium chloride in an amount o~ 1 to 18 percent, more preferably 1 to 3 percent, based upon the weight of water. As noted before, the presence of sodium chloride or ano-ther salt such as potassium chloride serves to depress the gel temperature of Component A of the invention composition.
The foregoing will generally serve to describe the invention to the reader and enable him to practice the invention within the guidelines outlined above.
The following exemplary em~odiments will further describe the invention and prepare the reader to practice same.
28,628 F 18-A composition of the invention is prepared by dry blending about 11.7 parts of Klucel~ J hydxoxypropyl-cellulose, sold by Hercules, Inc.; about 8.9 parts by weight 7L carboxymethylcellulose also sold by Hercules, Inc.;
about ~3.~ parts of a bentonite which meets the specifi~
cation set forth API standard lOA; and about 6.1 parts Lomar~
D surfactant, a sodium polynapthalene sulfonate sold by Nopco Chemical, (all parts by weight herein unless otherwise designated). ~s can be seen by re~erence to the preceding 10 body of this specification, the first component corresponds to component A of the inven~ion, the combination of the second and third components correspond to component B of the invention and the fourth component corresponds to Component C of the in~ention. Additionally, a small quantity o a dye may be added to the composi~ion to aid in identification of the returns from a wellbore if desired. A blend of the foregoing components is hereafter referred to as Blend A and is employed in the following e~amples to prepare an aqueous treatment fluid by adding 16.3 pounds of Blend A to 41 gallons of fresh water to make one barrel of a~ueous treatment fluid A having a density o~ 8.6 pounds per gallon (hereafter ppg). To prepare an aqueous treatment 1uid of greater density, a ~uantity o~ weighting agent is either pre~lended with the dry Blend A or added after Blend ~ is dispersed into the water. The amount of weighting agent to be employed can be determined from the following equation X = (42 P - 362) /(1 - VE) where X represents pounds of weighting agent to be added per barrel of aqueous treatment fluid, V represents the absolute volume of the weighting agent in gallons per pound and P represents the density of the treatment fluid desired in pounds per gallon. For barite, which is employed to weight the a~ueous treatment fluids in the following Registered Trade Mark 28,628-F -19-~5~
~20-examples, V = 0.278. Generally the aqueous treatment fluid should be designed to have a greaier density than the drilling mud which it will be displacing but less d~nsity than the fluid which is following it, e.g. the cement slurry. Preferably, it should be at least about 0.2 ppg heavier than the drilling mud and more preferably at least l ppg heavier than the drilling mud.
Example l ~ Mud Com~atibility A sample of aqueous treatment Fluid A is prepared in the manner described above and weighted to a given density with the appropriate quantity of barite.
Samples of synthetic drilling muds are prepared and then mixed in various proportions with aqueous treatment Fluid A weighted with barite to a density approximately l ppg greater than that of the mud. The respectiv~
apparent viscosity (expressed as 0300 reading) is measured on the model 35 Fann VG viscometer, as pre-viously described at a 300 rpm reAding. Fluid B is the same composition as Fluid A except that l percent (based on weight of water, BWOW) of a nonionic sur-actant, a 10 mole adduct of ethylene oxide to di(sec~
butyl) phenol is added for better compatibility with based mud.
The drilling mud samples are prepared by thoroughly mixing the dry components with fresh water in a Waring blender then permitted to hydrate for about a 24 hour period. The compositions are:
Mud A:
Density - 10 ppg 500 parts wa-ter 20 parts Wyoming bentonite 125 parts barite 28,628-F-20-~85~
Mud B:
Density - 14 ppg 500 parts water 30 parts Wyoming bentonite
2.5 parts Q-Broxin, a ferrochrome lignosulfonate marked by Baroid parts barite Mud C:
Density - 13.2 ppg As commercial invert emulsion based mud obtained directly from field operations which is prepared from a concentrate marketed as Vertoil by Magcobar and which contains a bentonitic clay in the aqueou~
phase and is weighted with barite.
Compatibilit~ata Run No. Fluid Mud Fluid Mud ~300 Reading 1 A(ll ppg) A 0:100 8 2 A(ll ppg) A 50:50 40
Density - 13.2 ppg As commercial invert emulsion based mud obtained directly from field operations which is prepared from a concentrate marketed as Vertoil by Magcobar and which contains a bentonitic clay in the aqueou~
phase and is weighted with barite.
Compatibilit~ata Run No. Fluid Mud Fluid Mud ~300 Reading 1 A(ll ppg) A 0:100 8 2 A(ll ppg) A 50:50 40
3 A(ll ppg) A 100:0 70
4 A(15 ppy) B 0:100 20 A(15 pp~) B 50:50 107 6 A(15 ppg) B 100:0 104 7 B(14 ppg) C 0:100 84 8 B(14 ppg) C 50:50 60 g B(14 pp~) C 100:0 47 28,628-F -21-o~7~7 As the data demonstrates, good compatibility exists between the aqueous treatment fluids and the various muds.
Example 2 - Cement ComEatibillty Several cement slurries are prepared from commonly available cementing materials and are tested for their compatibility with Fluid A in a fashion similar to ~hat employed in Example 1 by mixing and ~hen comparing the resulting ~300 reading to that of Fluid ~ above and the cement slurry alone. Fluid ~ is weighted to 12 to 15 ppg with barite.
The cement slurries are made up as follows:
(all parts by weight) Cement A:
Density - 18 ppg 596 parts Oklahoma Class H cement 226 parts water 6 parts dispersant (same as Component C
in Fluid A) 1.2 parts sugar-type high temperature retarder 179 parts fine sand 80 parts hematite Cement B:
Densiky ~ 16 ppg 678 parts Oklahoma Class H
285 parts water 2 parts lignosulfonate retarder 28,628-F-22~
-~3-Cement C:
~enslty ~ 13.3 ppg 307 parts Oklahoma Class H
153 parts flyash 33~ parts water 6 parts bentonite 1 part lignosulfonate retarder ~l~erlt Fluid: Cement Run No.Fluld CementVol. Ratio ~300 A( 15 ppg) A 0 :100 81 2 A~15 ppg) A 50:50 92 3 A(15 ppg) A 100:0 120 4 A( 15 ppg) B 0 :100 81
Example 2 - Cement ComEatibillty Several cement slurries are prepared from commonly available cementing materials and are tested for their compatibility with Fluid A in a fashion similar to ~hat employed in Example 1 by mixing and ~hen comparing the resulting ~300 reading to that of Fluid ~ above and the cement slurry alone. Fluid ~ is weighted to 12 to 15 ppg with barite.
The cement slurries are made up as follows:
(all parts by weight) Cement A:
Density - 18 ppg 596 parts Oklahoma Class H cement 226 parts water 6 parts dispersant (same as Component C
in Fluid A) 1.2 parts sugar-type high temperature retarder 179 parts fine sand 80 parts hematite Cement B:
Densiky ~ 16 ppg 678 parts Oklahoma Class H
285 parts water 2 parts lignosulfonate retarder 28,628-F-22~
-~3-Cement C:
~enslty ~ 13.3 ppg 307 parts Oklahoma Class H
153 parts flyash 33~ parts water 6 parts bentonite 1 part lignosulfonate retarder ~l~erlt Fluid: Cement Run No.Fluld CementVol. Ratio ~300 A( 15 ppg) A 0 :100 81 2 A~15 ppg) A 50:50 92 3 A(15 ppg) A 100:0 120 4 A( 15 ppg) B 0 :100 81
5 A( 15 ppg) B 50:50 83
6 A~15 ppg) B 100:0 120
7 A(12 ppg) C 0:100 36
8 A( 12 ppg) C 50: 50 39
9 A(12 ppg) C 100:0 63 Good compatibility between the aqueous treatment fluid and the cement slurries exists, as can be seen from the preceding data.
28, 628-F -23-2~-Example 3 - Transition Temperature Variation A sample of Fluid ~ (unweighted 8.6 ppg) is examined for the effect which addi~ion of sodium chloride has on its transition temperature. This temperature is determined by taking ~300 and ~600 readings at various incremental temperatures over a range and calculating when the yield point of the fluid tested goes to zero, i-e- when 2H300 ~ ~600 = - The transition temperature for Fluid A, unweighted, is in this fashion de~ermined to be about 135F. The effect of increasing amounts of salt is apparent from the following table.
Transition Temperatures (Base is Fluid A - 8.6 ppg) Amount SaltTransition 15 Run No. (% BWOW~ _Temp.
1 0 135~
3 7.5 105F
Exam~le 4 - Fluid Loss Control In accordance with API RP 10B Section 8 (1972), or determination of fluid loss, Fluid A is tested at various densities by addition of barite and with varying amounts o:E salt. Most tests are at 200F but in some instances this temperature is varied. The Fluid is tested against a 325 mesh screen at 1000 psl pressure.
Fluid loss i5 reported below.
28,628-F -24-7~7 Fluid Loss ( Base is Fluid A ) Density Fluid Loss Run No. ~ Temeerature (mL~30 min. ) Fluid Loss with Salt ~Base is Fluid A - all at 200F~
Salt Fluid Lo6s 15Run No. Density (% RWOW) (mL/30 min. ) 11 11 10 a~3 28, 628-F 25-5~
As may be observed from the foregoing, excel-lent fluid loss control is maintained even at extremely high temperature and with high salt content. Filtra-tion out of Component A from Fluid A above the transition temperature and reexamination of fluid loss for the filtered fluld shows high fluid loss, indicating that precipitated Component A appears to be acting as a very effectiv~ fluid loss preventive agent above the transi-tion temperature.
28, 628-F -23-2~-Example 3 - Transition Temperature Variation A sample of Fluid ~ (unweighted 8.6 ppg) is examined for the effect which addi~ion of sodium chloride has on its transition temperature. This temperature is determined by taking ~300 and ~600 readings at various incremental temperatures over a range and calculating when the yield point of the fluid tested goes to zero, i-e- when 2H300 ~ ~600 = - The transition temperature for Fluid A, unweighted, is in this fashion de~ermined to be about 135F. The effect of increasing amounts of salt is apparent from the following table.
Transition Temperatures (Base is Fluid A - 8.6 ppg) Amount SaltTransition 15 Run No. (% BWOW~ _Temp.
1 0 135~
3 7.5 105F
Exam~le 4 - Fluid Loss Control In accordance with API RP 10B Section 8 (1972), or determination of fluid loss, Fluid A is tested at various densities by addition of barite and with varying amounts o:E salt. Most tests are at 200F but in some instances this temperature is varied. The Fluid is tested against a 325 mesh screen at 1000 psl pressure.
Fluid loss i5 reported below.
28,628-F -24-7~7 Fluid Loss ( Base is Fluid A ) Density Fluid Loss Run No. ~ Temeerature (mL~30 min. ) Fluid Loss with Salt ~Base is Fluid A - all at 200F~
Salt Fluid Lo6s 15Run No. Density (% RWOW) (mL/30 min. ) 11 11 10 a~3 28, 628-F 25-5~
As may be observed from the foregoing, excel-lent fluid loss control is maintained even at extremely high temperature and with high salt content. Filtra-tion out of Component A from Fluid A above the transition temperature and reexamination of fluid loss for the filtered fluld shows high fluid loss, indicating that precipitated Component A appears to be acting as a very effectiv~ fluid loss preventive agent above the transi-tion temperature.
10 ~ ~, ~
In accordance with ~PI RP 10B, SectiQn 7, (1972~ thickening time tests are run at about 197F on various mixtures of cement slurries and Fluid A (weighted to 15 ppg with barite3 to determine whether the desired retarding effect of common retarders is inhibited by the composition o Fluid A - with fresh or salt water.
No undue acceleration is experienced for 20:80 and 40:60 (vol) Fluid A: cement mixtures for slurries employing lignosulfonate and a sugar~type high tempera-ture retarder, even in the presence of up to 10 percentsalt (BWOW in Fluid A).
E~ample 6 - K1 ematic Viscosities The kinematic viscosity of Fluid A alone and weighted with barite is determined from the ~300 reading at temperatures from 80 to 180F, by dividing the e300 reading (which is equal to the apparent viscosity in centipoises) by the density of the respec-tive fluid.
These kinematic viscosities a-t the various temperatures are shown below.
28,628-F -26-~8~
,~
o ~
U o U~ ~
~n N d~ ~:) N d~ D CO ~D d~D O t~ O C~ r~
r~
I
~ V~
., O ~ ~ ~ O O 0~ ~ ~ dl ~ ~ ~ O CO r~
O U~ ~ ~1 ~ C~ ~ ~1 1' ~ ~ ~ O
~) CD
~a .,~ ' ~,._ O~
U ~ 0~
O
o ~ ~o o o ~ ~ o o Lr) o o o ~ ~n o o ~n ~ ~ ~ ,~
.,~ r~ ~
td Ul `--~o E~
~ -1~ Q ~ ~ ~ ~O
a ,, ~
o z P~
28, 628-F -27-Example 7 - Fluid C
Another aqueous ~reatment fluid of the invention is prepared in a manner similar to that for Fluid A, above, except that a polyethylene glycol of about 6000 molecular weight is substi.tuted for Component C of Fluid A, the sodium polynaphthalene sulfonate.
Fluid C is prepared by adding to 500 parts water, while shearing in a Waring hlender, about 30.5 parts of the following blend of materials (by weight):
26.2 parts Klucel~ J hydroxypropylcellulose 8.2 parts 7L Carboxymethylcelllllose parts Wyoming bentonite parts polyethylene glycol - 600 mol. wt.
The resulting Fluid C has a density of 8.6 ppg. To attain the ~ollowing densities, the respective quantities of barite are added to Fluid C having the foregoing propoxtions:
10 ppg ~ 120 parts barite 13 ppg - 430 parts barite 14 ppg - 545 parts barite When combined with cement slurries or with a drilling mud of the nature of Mud B, and tested as in ~xample 1, Fluid C is found to have a transition temperature of approximately 120F which is depressed in much the same fashion as Fluid A by addition of salt. Excellent fluid 106s of about 15-20 mL/30 min is exhibited by Fluid C at 200F.
Example 8 - Method of Use Fluid A, weighted to about 13.5 ppg with barite, is employed in an intermediate casing cementing operation as spacer to displace an 11.6 ppg water-based Registered Trade Mark 28,628-F -28--29~ 7~7 drilling mud from a borehole at a depth of about 13,250 feet, having a B.H.C.T. of about 156F. About 40 barrels of the spacer are pumped down the 7 5/8 inch O.D. intermediate casing and up the annulus of the 9 7/8 inch borehole at about 6 barrels per minute.
The spacer is followed by about 227 barrels of a 13.8 ppg and then 38 barrels of a 16.7 ppg Class H
cement slurry and the same rate. Since 156~F B.~.C.T.
exceeds the transition temperature of Fluid A, and since 6 barrel per minue pu~p rate exceeds the critical velocity for Fluid A at tha~ temperature in an annulus of that size, the spacer is in turbulent flow while traveling through the annulus. An excellen~ cement bond to both casing and borehole wall is obtained as a result.
Having thus described the invention, it will be understocd that such description has been given by way of illustration and example and not by way of limitation.
28,628-F -29-
In accordance with ~PI RP 10B, SectiQn 7, (1972~ thickening time tests are run at about 197F on various mixtures of cement slurries and Fluid A (weighted to 15 ppg with barite3 to determine whether the desired retarding effect of common retarders is inhibited by the composition o Fluid A - with fresh or salt water.
No undue acceleration is experienced for 20:80 and 40:60 (vol) Fluid A: cement mixtures for slurries employing lignosulfonate and a sugar~type high tempera-ture retarder, even in the presence of up to 10 percentsalt (BWOW in Fluid A).
E~ample 6 - K1 ematic Viscosities The kinematic viscosity of Fluid A alone and weighted with barite is determined from the ~300 reading at temperatures from 80 to 180F, by dividing the e300 reading (which is equal to the apparent viscosity in centipoises) by the density of the respec-tive fluid.
These kinematic viscosities a-t the various temperatures are shown below.
28,628-F -26-~8~
,~
o ~
U o U~ ~
~n N d~ ~:) N d~ D CO ~D d~D O t~ O C~ r~
r~
I
~ V~
., O ~ ~ ~ O O 0~ ~ ~ dl ~ ~ ~ O CO r~
O U~ ~ ~1 ~ C~ ~ ~1 1' ~ ~ ~ O
~) CD
~a .,~ ' ~,._ O~
U ~ 0~
O
o ~ ~o o o ~ ~ o o Lr) o o o ~ ~n o o ~n ~ ~ ~ ,~
.,~ r~ ~
td Ul `--~o E~
~ -1~ Q ~ ~ ~ ~O
a ,, ~
o z P~
28, 628-F -27-Example 7 - Fluid C
Another aqueous ~reatment fluid of the invention is prepared in a manner similar to that for Fluid A, above, except that a polyethylene glycol of about 6000 molecular weight is substi.tuted for Component C of Fluid A, the sodium polynaphthalene sulfonate.
Fluid C is prepared by adding to 500 parts water, while shearing in a Waring hlender, about 30.5 parts of the following blend of materials (by weight):
26.2 parts Klucel~ J hydroxypropylcellulose 8.2 parts 7L Carboxymethylcelllllose parts Wyoming bentonite parts polyethylene glycol - 600 mol. wt.
The resulting Fluid C has a density of 8.6 ppg. To attain the ~ollowing densities, the respective quantities of barite are added to Fluid C having the foregoing propoxtions:
10 ppg ~ 120 parts barite 13 ppg - 430 parts barite 14 ppg - 545 parts barite When combined with cement slurries or with a drilling mud of the nature of Mud B, and tested as in ~xample 1, Fluid C is found to have a transition temperature of approximately 120F which is depressed in much the same fashion as Fluid A by addition of salt. Excellent fluid 106s of about 15-20 mL/30 min is exhibited by Fluid C at 200F.
Example 8 - Method of Use Fluid A, weighted to about 13.5 ppg with barite, is employed in an intermediate casing cementing operation as spacer to displace an 11.6 ppg water-based Registered Trade Mark 28,628-F -28--29~ 7~7 drilling mud from a borehole at a depth of about 13,250 feet, having a B.H.C.T. of about 156F. About 40 barrels of the spacer are pumped down the 7 5/8 inch O.D. intermediate casing and up the annulus of the 9 7/8 inch borehole at about 6 barrels per minute.
The spacer is followed by about 227 barrels of a 13.8 ppg and then 38 barrels of a 16.7 ppg Class H
cement slurry and the same rate. Since 156~F B.~.C.T.
exceeds the transition temperature of Fluid A, and since 6 barrel per minue pu~p rate exceeds the critical velocity for Fluid A at tha~ temperature in an annulus of that size, the spacer is in turbulent flow while traveling through the annulus. An excellen~ cement bond to both casing and borehole wall is obtained as a result.
Having thus described the invention, it will be understocd that such description has been given by way of illustration and example and not by way of limitation.
28,628-F -29-
Claims (32)
PROPERTY OR PRIVILEGE IS CLAIMED ARE DEFINED AS FOLLOWS:
1. An aqueous treatment fluid which has a yield point of zero at a temperature between 30° and 71°C and is compatible with cement slurries and drilling muds employed in the completion and drilling of subter-ranean boreholes, which treatment fluid comprises:
Component (A) A viscosifier which is soluble in and increases the kinematic viscosity of water at temperatures between 4° and 38°C and which becomes substantially insoluble in said treatment fluid at a temperature between 30°
and 71°C;
Component (B) A thickener which is different than Component (A) and soluble or dispersible in and increases the kinematic viscosity of water at temperatures between 4° and 71°C;
Component (C) A dispersant which enhances the dispersibility of Component (A) in water;
Component (D) A weighting agent; and Component (E) Water;
wherein said Components are present in amounts sufficient to impart a kinematic viscosity to said treatment fluid, at a temperature between 30° and 71°C, of greater than 0.1 and less than 7.5 .
Component (A) A viscosifier which is soluble in and increases the kinematic viscosity of water at temperatures between 4° and 38°C and which becomes substantially insoluble in said treatment fluid at a temperature between 30°
and 71°C;
Component (B) A thickener which is different than Component (A) and soluble or dispersible in and increases the kinematic viscosity of water at temperatures between 4° and 71°C;
Component (C) A dispersant which enhances the dispersibility of Component (A) in water;
Component (D) A weighting agent; and Component (E) Water;
wherein said Components are present in amounts sufficient to impart a kinematic viscosity to said treatment fluid, at a temperature between 30° and 71°C, of greater than 0.1 and less than 7.5 .
2. The treatment fluid of Claim 1 which further comprises Component (F), a nonionic surfactant, in an amount sufficient to render the treatment fluid compatible with oil-based drilling mud.
3. The treatment fluid of Claim 2, wherein Component (F) comprises a nonionic, alkoxylated alcohol.
4. The treatment fluid of Claim 1 wherein water comprises at least about 40 percent of said treatment fluid by weight.
5. The treatment fluid of Claim 1, wherein Component (B) is capable of imparting a kinematic viscosity of at least about 15 to the treatment fluid at the maximum temperature below about 71°C to which the treatment fluid will be subjected, and P is the density of the treatment fluid, also without Com-ponent (A), in pounds per gallon.
6. The treatment fluid of Claim 1 wherein Component (A) comprises a hydroxyalkylcellulose wherein the hydroxyalkyl moieties thereof are selected from hydroxyethyl, hydroxypropyl and hydroxylbutyl, Component (B) comprises a sulfonated aromatic compound or salt thereof.
7. The treatment fluid of Claim 6 wherein Com-ponent (A) comprises a hydroxypropylcellulose, Component (B) comprises a combination of a carboxymethylcellulose and bentonite, and Component (C) comprises a sodium salt of sulfonated polynaphthalene.
8. The treatment fluid of Claim 1 wherein Component (A) comprises from 0.1 to 1.5 percent, Component (B) comprises from 0.5 to 4 percent, Component (C) comprises from 0.1 to 2.5 percent, Component (E) comprises from 90 to 98 percent, and a non-ionic surfactant Component (F) in an amount of from 0 to 2 percent of the combined weight of said components of the treatment fluid.
9. The treatment fluid of Claim 8 which has an API static fluid loss (1000 psi at 350°F) of no greater than about 150 mL/30 min.
10. The treatment fluid of Claim 8 wherein Component (D) is present in an amount of from 1.5 percent to 150 percent based on the combined weight of Components (A), (B), (C), (E) and (F).
11. The treatment fluid of Claim 8 wherein Component (D) comprises particulated barite in an amount sufficient to impart a density of from 9 and 18 pounds per gallon to the treatment fluid.
12. The treatment fluid of Claim 11 wherein Component D comprises ilmenite or hematite in an amount sufficient to impart a density of up to about 20 pounds per gallon to the treatment fluid.
13. The treatment fluid of Claim 1 wherein the kinematic viscosity of the treatment fluid is between 0.3 and 6.5 .
14. The treatment fluid of Claim 1 including sodium chloride or potassium chloride in an amount of from 1 to 18 percent, based on the weight of Component (E).
15. The treatment fluid of Claim 8 wherein Component (B) is a water-swellable extender selected from water-swellable clays of attapulgite and bentonite.
16. The treatment fluid of Claim 15 wherein said water-swellable extender is a sodium bentonite.
17. In a method for injecting a fluid into a borehole containing a drilling mud, wherein the fluid is not compatible with the mud and wherein injection of said fluid is preceded by injection of a composition compatible with both the mud and the fluid, the improvement comprising: injecting a sufficient quantity of said composition to separate said mud and said fluid, at an injection velocity which exceeds the critical velocity for said composition in the borehole at the bottom hole circu-lating temperature of said borehole, where the composition comprises the aqueous treatment fluid of Claim 1.
18. The method of Claim 17 wherein the fluid injected comprises an aqueous cement slurry.
19. The method of Claim 17 wherein the mud is a water-based mud.
20. The method of Claim 17 wherein the mud is an oil-based mud and the composition further comprises Component (F), a noniomic surfactant, in an amount sufficient to render the treatment fluid compatible with said oil-based mud.
21. The method of Claim 19 wherein the fluid injected comprises an aqueous hydraulic cement slurry.
22. The method of Claim 21 wherein the fluid is injected at a flow rate of from about 1 to about 12 barrels per minute.
23. The method of Claim 22 wherein the bottom hole circulating temperature (B.H.C.T.) is between about 85° and about 350°F.
24. The method or Claim 23 wherein the B.H.C.T.
is between about 150° and about 250°F.
is between about 150° and about 250°F.
25. The method of Claim 23 wherein the B.H.C.T. is between about 125° and about 145°F.
26. The method of Claim 21 wherein said fluid injected is thixotropic.
27. The method of Claim 21 wherein the aqueous treatment fluid further comprises sodium chloride in an amount of about 1 to about 18 percent, based on the weight of Component (E).
28. The method of Claim 21 wherein the kinematic viscosity of the aqueous treatment fluid is between about 0.3 and about 6.5
29. The method of Claim 21 wherein said aqueous treatment fluid, Component (A) comprises a hydroxyalkyl-cellulose, Component (B) comprises a combination of a carboxymethylcellulose and a water-swellable extender, Component (C) comprises a sulfonated hydrocarbon compound or salt thereof, and Component (F), where present, comprises a nonionic, alkoxylated alcohol.
30. The method of Claim 29 wherein Component (A) comprises a hydroxypropylcellulose, Component (B) comprises a combination of a carboxymethylcellulose and bentonite, Component (C) comprises a sodium salt of a sulfonated polynaphthalene and Component (F), where present, comprises an ethoxylated- alkanol or -alkylphenol.
31. The method of Claim 21 wherein said aqueous treatment fluid, Component (A) comprises about 0.1 to about 1.5 percent, Component (B) comprises about 0.5 to about 4 percent, Component (C) comprises about 0.1 to about 2.5 percent, Component (E) comprises about 90 to about 98 percent and Component (F) comprises about 0 to about 2 percent of the combined weight of said components of said treatment fluid.
32. The method of Claim 31 wherein Component (D) is present in an amount of about 1.5 percent to about 150 percent based on the combined weight of Components (A), (B), (C), (E) and (F).
Priority Applications (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA000390787A CA1185777A (en) | 1981-11-24 | 1981-11-24 | Aqueous treatment fluid and method of use |
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA000390787A CA1185777A (en) | 1981-11-24 | 1981-11-24 | Aqueous treatment fluid and method of use |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CA1185777A true CA1185777A (en) | 1985-04-23 |
Family
ID=4121488
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA000390787A Expired CA1185777A (en) | 1981-11-24 | 1981-11-24 | Aqueous treatment fluid and method of use |
Country Status (1)
| Country | Link |
|---|---|
| CA (1) | CA1185777A (en) |
-
1981
- 1981-11-24 CA CA000390787A patent/CA1185777A/en not_active Expired
Similar Documents
| Publication | Publication Date | Title |
|---|---|---|
| US4646834A (en) | Aqueous treatment fluid and method of use | |
| US5789352A (en) | Well completion spacer fluids and methods | |
| US4588032A (en) | Fluid spacer composition for use in well cementing | |
| CA1082438A (en) | Spacer composition and method of use | |
| CA1296514C (en) | Drilling and completion fluid | |
| US6887833B2 (en) | Oil based compositions and method for temporarily sealing subterranean zones | |
| US5030366A (en) | Spacer fluids | |
| US3465825A (en) | Aqueous cementing composition adaptable to high turbulent flow and low fluid loss to porous contacting surfaces,and method of cementing a well using same | |
| AU2009294452B2 (en) | Inhibitive water-based drilling fluid system and method for drilling sands and other water-sensitive formations | |
| CA1121145A (en) | Drilling fluid containing crosslinked polysaccharide derivative | |
| CA2564566C (en) | Inhibitive water-based drilling fluid system and method for drilling sands and other water-sensitive formations | |
| CA2258321A1 (en) | Method and spacer fluid composition for displacing drilling fluid from a wellbore | |
| CN106661929A (en) | Water-based wellbore servicing fluids with high temperature fluid loss control additive | |
| WO1996019544A2 (en) | Drill-in fluids and drilling methods | |
| EP0289529A1 (en) | Viscosifiers for brines utilizing hydrophilic polymer-mineral oil systems. | |
| US4559149A (en) | Workover fluid | |
| WO1998054432A2 (en) | Mud suspension control system | |
| US3123559A (en) | Hccjhio | |
| EP0079997B1 (en) | Aqueous treatment fluid and method for its use in the drilling of wells | |
| US3042607A (en) | Drilling fluid | |
| CA1185777A (en) | Aqueous treatment fluid and method of use | |
| US5502030A (en) | Liquid additive comprising a sulfonated asphalt and processes therefor and therewith | |
| Hudson et al. | Fluid-loss control through the use of a liquid-thickened completion and workover brine | |
| US4778608A (en) | High temperature drilling mud composition | |
| NO157660B (en) | DIFFICULT TREATMENT LIQUID FOR USE IN COMPLETION AND DRILLING OF BORES, AND USE OF THE LIQUID BY INJECTION OF A CEMENT SUSPENSION IN DRILL. |
Legal Events
| Date | Code | Title | Description |
|---|---|---|---|
| MKEX | Expiry |