WO2005059301A1 - Zeolite-containing settable spotting fluids - Google Patents

Zeolite-containing settable spotting fluids Download PDF

Info

Publication number
WO2005059301A1
WO2005059301A1 PCT/GB2004/004899 GB2004004899W WO2005059301A1 WO 2005059301 A1 WO2005059301 A1 WO 2005059301A1 GB 2004004899 W GB2004004899 W GB 2004004899W WO 2005059301 A1 WO2005059301 A1 WO 2005059301A1
Authority
WO
WIPO (PCT)
Prior art keywords
wellbore
fluid
zeolite
oil
sodium
Prior art date
Application number
PCT/GB2004/004899
Other languages
French (fr)
Inventor
Karen Luke
Russell M. Fitzgerald
Frank Zamora
K. Santra Ashok
Original Assignee
Halliburton Energy Services, Inc.
Wain, Christopher, Paul
Priority date (The priority date 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 date listed.)
Filing date
Publication date
Application filed by Halliburton Energy Services, Inc., Wain, Christopher, Paul filed Critical Halliburton Energy Services, Inc.
Priority to CA002549515A priority Critical patent/CA2549515C/en
Publication of WO2005059301A1 publication Critical patent/WO2005059301A1/en

Links

Classifications

    • CCHEMISTRY; METALLURGY
    • C09DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09KMATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/42Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells
    • C09K8/46Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells containing inorganic binders, e.g. Portland cement
    • CCHEMISTRY; METALLURGY
    • C04CEMENTS; CONCRETE; ARTIFICIAL STONE; CERAMICS; REFRACTORIES
    • C04BLIME, MAGNESIA; SLAG; CEMENTS; COMPOSITIONS THEREOF, e.g. MORTARS, CONCRETE OR LIKE BUILDING MATERIALS; ARTIFICIAL STONE; CERAMICS; REFRACTORIES; TREATMENT OF NATURAL STONE
    • C04B12/00Cements not provided for in groups C04B7/00 - C04B11/00
    • C04B12/005Geopolymer cements, e.g. reaction products of aluminosilicates with alkali metal hydroxides or silicates
    • CCHEMISTRY; METALLURGY
    • C04CEMENTS; CONCRETE; ARTIFICIAL STONE; CERAMICS; REFRACTORIES
    • C04BLIME, MAGNESIA; SLAG; CEMENTS; COMPOSITIONS THEREOF, e.g. MORTARS, CONCRETE OR LIKE BUILDING MATERIALS; ARTIFICIAL STONE; CERAMICS; REFRACTORIES; TREATMENT OF NATURAL STONE
    • C04B14/00Use of inorganic materials as fillers, e.g. pigments, for mortars, concrete or artificial stone; Treatment of inorganic materials specially adapted to enhance their filling properties in mortars, concrete or artificial stone
    • C04B14/02Granular materials, e.g. microballoons
    • C04B14/04Silica-rich materials; Silicates
    • C04B14/047Zeolites
    • CCHEMISTRY; METALLURGY
    • C04CEMENTS; CONCRETE; ARTIFICIAL STONE; CERAMICS; REFRACTORIES
    • C04BLIME, MAGNESIA; SLAG; CEMENTS; COMPOSITIONS THEREOF, e.g. MORTARS, CONCRETE OR LIKE BUILDING MATERIALS; ARTIFICIAL STONE; CERAMICS; REFRACTORIES; TREATMENT OF NATURAL STONE
    • C04B28/00Compositions of mortars, concrete or artificial stone, containing inorganic binders or the reaction product of an inorganic and an organic binder, e.g. polycarboxylate cements
    • C04B28/006Compositions of mortars, concrete or artificial stone, containing inorganic binders or the reaction product of an inorganic and an organic binder, e.g. polycarboxylate cements containing mineral polymers, e.g. geopolymers of the Davidovits type
    • CCHEMISTRY; METALLURGY
    • C04CEMENTS; CONCRETE; ARTIFICIAL STONE; CERAMICS; REFRACTORIES
    • C04BLIME, MAGNESIA; SLAG; CEMENTS; COMPOSITIONS THEREOF, e.g. MORTARS, CONCRETE OR LIKE BUILDING MATERIALS; ARTIFICIAL STONE; CERAMICS; REFRACTORIES; TREATMENT OF NATURAL STONE
    • C04B28/00Compositions of mortars, concrete or artificial stone, containing inorganic binders or the reaction product of an inorganic and an organic binder, e.g. polycarboxylate cements
    • C04B28/02Compositions of mortars, concrete or artificial stone, containing inorganic binders or the reaction product of an inorganic and an organic binder, e.g. polycarboxylate cements containing hydraulic cements other than calcium sulfates
    • C04B28/10Lime cements or magnesium oxide cements
    • CCHEMISTRY; METALLURGY
    • C09DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09KMATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/02Well-drilling compositions
    • C09K8/04Aqueous well-drilling compositions
    • C09K8/14Clay-containing compositions
    • C09K8/16Clay-containing compositions characterised by the inorganic compounds other than clay
    • CCHEMISTRY; METALLURGY
    • C09DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09KMATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/42Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells
    • C09K8/46Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells containing inorganic binders, e.g. Portland cement
    • C09K8/467Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells containing inorganic binders, e.g. Portland cement containing additives for specific purposes
    • YGENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02PCLIMATE CHANGE MITIGATION TECHNOLOGIES IN THE PRODUCTION OR PROCESSING OF GOODS
    • Y02P40/00Technologies relating to the processing of minerals
    • Y02P40/10Production of cement, e.g. improving or optimising the production methods; Cement grinding
    • YGENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y10TECHNICAL SUBJECTS COVERED BY FORMER USPC
    • Y10STECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y10S507/00Earth boring, well treating, and oil field chemistry
    • Y10S507/925Completion or workover fluid

Definitions

  • the present embodiments relate generally to wellbore treating fluids introduced into a subterranean zone penetrated by a wellbore, particularly wellbore treating fluids introduced as settable spotting fluids.
  • a wellbore is drilled using a drilling fluid that is continuously circulated down a drill pipe, through a drill bit, and upwardly through the wellbore to the surface.
  • the drill bit is withdrawn from the wellbore, and circulation of the drilling fluid is stopped, thereby initiating a shutdown period.
  • the drilling fluid is typically left in the wellbore, and a filter cake of solids from the drilling fluid, and additional dehydrated drilling fluid and gelled drilling fluid, typically forms on the walls of the wellbore.
  • the next operation in completing the wellbore usually involves running a pipe string, e.g., casing, into the wellbore. While the pipe is being run, the drilling fluid left in the wellbore remains relatively static. During that time, the stagnant drilling fluid progressively increases in gel strength, whereby portions of the drilling fluid in the wellbore can become increasingly difficult to displace during subsequent clean-up operations.
  • the next operation typically involves cleaning out the wellbore, which may be accomplished by re-initiating circulation of drilling fluid.
  • the drilling fluid is circulated downwardly through the interior of the pipe and upwardly through the annulus between the exterior of the pipe and the walls of the wellbore, while removing drilling solids, gas, filter cake, dehydrated drilling fluid, gelled drilling fluid, and any other undesired substances needing to be removed from the wellbore.
  • primary cementing operations are typically performed therein. Namely, the pipe is cemented in the wellbore by placing a cement slurry in the annulus between the pipe and the walls of the wellbore.
  • the cement slurry sets into a hard impermeable mass, and is intended to bond the pipe to the walls of the wellbore whereby the annulus is sealed and fluid communication between subterranean zones or to the surface by way of the annulus is prevented.
  • problems can occur, including difficulty in removing portions of the drilling fluid, or inability to achieve a satisfactory bond between the pipe and the walls of the wellbore because of drilling fluid that remained in the wellbore during primary cementing operations. Difficulty in removing portions of the drilling fluid is often caused by an increase in the gel strength of the drilling fluid, which is often due to the amount of time the drilling fluid has been left stagnant in the wellbore.
  • polymeric viscosifiers and additives in the drilling fluid contribute to the formation of a filter cake that is generally very stable and can be difficult to remove. If appreciable drilling fluid and/or filter cake remain in the wellbore or on the walls of the wellbore, a satisfactory bond between the pipe, primary cement and the walls of the wellbore will not be achieved, which can lead to fluid leakage through the annulus and other problems. Removal of the drilling fluid and filter cake from the wellbore is often attempted by running flushes, washes or spacer fluids through the annulus between the pipe and the walls of the wellbore prior to cementing.
  • the present embodiments provide wellbore treating fluids in the form of settable spotting fluids that include zeolite as a settable material, and methods for causing the zeolite to set and using such settable spotting fluids in drilling operations. Description According to embodiments described herein, wellbore treating fluids comprising zeolite are introduced into a wellbore in the form of a settable spotting fluid.
  • Methods according to the present embodiments provide for introducing a wellbore treating fluid comprising zeolite into a wellbore penetrating a subterranean zone, introducing a subsequent composition comprising a compressive strength-developing amount of an activator into the wellbore to displace all but a remaining portion of the wellbore treating fluid from the wellbore, contacting the zeolite in the remaining portion of the wellbore treating fluid with the activator, and allowing the zeolite to set.
  • a wellbore treating fluid comprising zeolite, a compressive strength-developing amount of an activator, and a retarder
  • a wellbore penetrating a subterranean zone introducing a subsequent composition into the wellbore to displace all but a remaining portion of the wellbore treating fluid from the wellbore, and allowing the zeolite in the remaining portion of the wellbore treating fluid to set.
  • Setting of the zeolite according to the present embodiments is similar to the setting of settable materials in conventional settable spotting fluids, that is, the zeolite sets into a relatively hard mass.
  • the compressive strength of the set mass formed by the zeolite can be measured and compared to compressive strengths of set materials in conventional settable spotting fluids.
  • drilling fluid also referred to herein as "mud”
  • mud drilling fluid
  • the mud in the wellbore is displaced with the settable spotting fluid before the mud has had a chance to gain significant gel strength.
  • mud encompasses any fluid used in hydrocarbon drilling operations, including but not limited to all types of water-base, oil-base and synthetic-base drilling fluids, and fluids that contain significant amounts of suspended solids, emulsified water or oil.
  • a settable spotting fluid comprising zeolite at least partially displaces mud from the wellbore
  • the settable spotting fluid is subsequently flushed out of the wellbore by washes or spacer fluids circulated through the wellbore.
  • a cement slurry may then be pumped into the annulus and allowed to set, thus bonding the pipe to the walls of the wellbore.
  • a settable spotting fluid comprising zeolite at least partially displaces mud from a wellbore
  • portions of the settable spotting fluid remain on the walls of the wellbore as part of the filter cake, and/or in permeable areas affecting the wellbore, such as fissures, fractures, caverns, vugs, thief zones, low pressure subterranean zones or high pressure subterranean zones, even if washes or spacer fluids are introduced into the wellbore subsequent to the settable spotting fluid.
  • a subsequent composition for example, a drilling fluid, pill, spotting fluid or other mud, which contains at least one activator, is pumped into the wellbore.
  • the subsequent composition is pumped into the wellbore, either after the settable spotting fluid, or after the washes or spacer fluids, if such are used.
  • the activator in the subsequent composition contacts the settable spotting fluid remaining in the filter cake and/or permeable areas, the activator causes the zeolite therein to set.
  • the activator is present in the subsequent composition in a compressive strength-developing amount, and may be one or more of calcium hydroxide, sodium silicate, sodium fluoride, sodium silicofluoride, magnesium silicofluoride, zinc silicofluoride, sodium carbonate, potassium carbonate, sodium hydroxide, potassium hydroxide, sodium sulfate, and mixtures thereof. Selection of the type and amount of an activator(s) largely depends on the type and make-up of the composition in which the activator is contained, and it is within the means of those of ordinary skill in the art to select a suitable type and amount of activator.
  • primary cementing operations are performed by introducing a cement slurry containing at least one activator into the wellbore.
  • the cement slurry can be introduced after the settable spotting fluid to displace the settable spotting fluid from the wellbore, or can be introduced after a wash or spacer fluid that was pumped into the wellbore after the settable spotting fluid.
  • the activator As the cement slurry is pumped, and as it begins to set in the wellbore, the activator therein diffuses into the settable spotting fluid remaining in the filter cake and/or permeable areas, and causes the zeolite to set.
  • the activator is present in the cement slurry in a compressive strength-developing amount, and may be one or more of calcium hydroxide, sodium silicate, sodium fluoride, sodium silicofluoride, magnesium silicofluoride, zinc silicofluoride, sodium carbonate, potassium carbonate, sodium hydroxide, potassium hydroxide, sodium sulfate, and mixtures thereof.
  • a settable spotting fluid comprising zeolite, a compressive strength-developing amount of at least one activator and at least one retarder is introduced into a wellbore. Portions of the settable spotting fluid remain on the walls of the wellbore as part of the filter cake, and/or in permeable areas affecting the wellbore, even if washes or spacer fluids are introduced into the wellbore subsequent to the settable spotting fluid.
  • the activator in the settable spotting fluid causes the zeolite in the remaining portions to set, while the retarder slows the set so that it occurs over a desired period of time.
  • other drilling operations can proceed, which operations may require other muds, fluids, or compositions to be subsequently pumped into the wellbore. If subsequent muds, fluids, or compositions are pumped into the wellbore, they may or may not comprise an activator.
  • the activator in the settable spotting fluid may be one or more of calcium hydroxide, sodium silicate, sodium fluoride, sodium silicofluoride, magnesium silicofluoride, zinc silicofluoride, sodium carbonate, potassium carbonate, sodium hydroxide, potassium hydroxide, sodium sulfate, and mixtures thereof.
  • Suitable retarders include but are not limited to one or more of a lignosulfonate, an organic acid having an ⁇ -hydroxy group such as citric acid, tartaric acid or gluconic acid, and combinations of both lignosulfonate and organic acid having an ⁇ -hydroxy group.
  • selection of the type and amount of activators) and retarder(s) largely depends on the nature and composition of the settable spotting fluid, and it is within the means of those of ordinary skill in the art to select a suitable type and amount of activator and retarder. Moreover, it is within the means of those of ordinary skill in the art to exert control over the amount of time that it takes the zeolite to set by determining, through the exercise of routine experimentation, the amount of retarder necessary to achieve a set over a desired period of time.
  • a settable spotting fluid comprising zeolite also provides a method by which zeolite remaining in the wellbore after displacement of the settable spotting fluid can be caused to set.
  • Zeolite that sets in permeable areas affecting the wellbore such as fissures, fractures, caverns, vugs, thief zones, low pressure subterranean zones or high pressure subterranean zones effectively seals such permeable areas, thereby preventing the entry or flow of formation fluids into the annulus.
  • Zeolites are porous alumino-silicate minerals that may be either a natural or manmade material.
  • Manmade zeolites are based on the same type of structural cell as natural zeolites, and are composed of aluminosilicate hydrates having the same basic formula as given below. It is understood that as used in this application, the term "zeolite” means and encompasses all natural and manmade forms of zeolites. All zeolites are composed of a three-dimensional framework of SiO 4 and AlO 4 in a tetrahedron, which creates a very high surface area. Cations and water molecules are entrained into the framework.
  • all zeolites may be represented by the crystallographic unit cell formula: M a/n [(AlO 2 ) a (SiO 2 ) b ] - xH 2 O
  • M represents one or more cations such as Na, K, Mg, Ca, Sr, Li or Ba for natural zeolites and NH,, CH 3 NH 3 , (CH 3 ) 3 NH, (CH 3 ) 4 N, Ga, Ge and P for manmade zeolites
  • n represents the cation valence
  • the ratio of b:a is in a range from greater than or equal to 1 and less than or equal to 5
  • x represents the moles of water entrained into the zeolite framework.
  • Preferred zeolites for use in the wellbore treating fluids of the present embodiments include analcime (hydrated sodium aluminum silicate), bikitaite (lithium aluminum silicate), brewsterite (hydrated strontium barium calcium aluminum silicate), chabazite (hydrated calcium aluminum silicate), clinoptilolite (hydrated sodium aluminum silicate), faujasite (hydrated sodium potassium calcium magnesium aluminum silicate), harmotome (hydrated barium aluminum silicate), heulandite (hydrated sodium calcium aluminum silicate), laumontite (hydrated calcium aluminum silicate), mesolite (hydrated sodium calcium aluminum silicate), natrolite (hydrated sodium aluminum silicate), paulingite (hydrated potassium sodium calcium barium aluminum silicate), phillipsite (hydrated potassium sodium calcium aluminum silicate), scolecite (hydrated calcium aluminum silicate), stellerite (hydrated calcium aluminum silicate), stilbite (hydrated sodium calcium aluminum silicate) and thomsonite (hydrated sodium calcium aluminum silicate).
  • analcime hydrated sodium aluminum silicate
  • the zeolites for use in the wellbore treating fluids of the present embodiment include chabazite and clinoptilolite.
  • Carrier fluids suitable for use in the embodiments of wellbore treating fluids such as settable spotting fluids disclosed herein, comprise aqueous fluids, oil-based and synthetic- based fluids, emulsion, acids, or mixtures thereof.
  • Exemplary aqueous fluids include but are not limited to water and water-based gels.
  • the carrier fluid comprises water
  • the water can be fresh water, imsaturated salt solution, including brines and seawater, and saturated salt solution.
  • Exemplary oil-based fluids include but are not limited to canola oil, kerosene, diesel oil, fish oil, mineral oil, sunflower oil, corn oil, soy oil, olive oil, cottonseed oil, peanut oil and paraffin.
  • Exemplary synthetic-based fluids include but are not limited to esters, olefins and ethers.
  • the preferred carrier fluid for the wellbore treating fluid comprising zeolite as disclosed herein depends upon the properties desired for the wellbore treating fluid, as well as the cost, availability, temperature, stability, viscosity, clarity, and the like of the carrier fluid.
  • a settable spotting fluid comprising zeolite is prepared by mixing an amount of zeolite with a carrier fluid in an amount of from about 100 to about 200 weight percent, based on the weight of the amount of zeolite.
  • the mud can be a water-based drilling fluid, an oil-based drilling fluid, or a synthetic- based drilling fluid.
  • a wellbore treating fluid comprising zeolite and at least one carrier fluid is introduced into a wellbore to at least partially displace a mud from the wellbore.
  • a subsequent composition is introduced into the wellbore to displace all but a remaining portion of the wellbore treating fluid from the wellbore.
  • the zeolite in the remaining portion of the wellbore treating fluid sets into a relatively hard mass. Displacement of the mud from the wellbore and setting of zeolite remaining in the wellbore contribute to the creation of satisfactory conditions for primary cementing operations.
  • setting of zeolite that remained in one or more permeable areas affecting the wellbore such as fissures, fractures, caverns, vugs, thief zones, low pressure subterranean zones or high pressure subterranean zones effectively seals such permeable areas, thereby preventing the entry or flow of formation fluids into the annulus.
  • EXAMPLE 1 Six settable spotting fluids ("Spots") were prepared by combining the components as set forth in TABLE 1 below. Specifically, the zeolite and the hydrated lime were dry-mixed by hand in a glass jar. This dry mix was then added over a 15 second period to a carrier fluid being maintained in a Waring blender at 4,000 RPM. The blender speed was then increased to 12,000 RPM and mixing was continued for 35 seconds. According to the embodiments illustrated in Table 1, the carrier fluid was water.
  • each settable spotting fluid is reported in the table as a "% bwoZ", which indicates a weight percent based on the weight of the zeolite.
  • Chabazite was used as the zeolite for Spots 1 - 4
  • clinoptilolite was used as the zeolite for Spots 5 - 6.
  • Each of these zeolites is commercially available from C2C Zeolite Corporation of Calgary, Canada.
  • the compressive strength for each of Spots 1 - 6 was determined by Non-Destructive Sonic Testing as set forth in API Specification 10B 22nd Edition, 1997, of the American Petroleum Institute, the entire disclosure of which is incorporated herein by reference as if reproduced in its entirety. As reported in Table 1, the compressive strength was measured at 160°F at the reported elapsed times. The measured compressive strength is reported in Table 1 in pounds per square inch (psi).
  • the compressive strength data indicates that wellbore treating fluids comprising zeolite and water, such as the settable spotting fluids illustrated in Example 1, develop compressive strengths when the amount of an activator, such as lime, is present in an amount greater than about 7% based on the weight of the zeolite.
  • the identity of the activator, zeolite, and carrier fluid may influence the amount of activator necessary to cause the settable spotting fluid to set; thus, in some embodiments, the settable spotting fluid may develop compressive strength with activator amounts less than the 7% illustrated by Example 1. Accordingly, the amount of activator used in practicing the present embodiments need only be at least a compressive strength-developing amount.
  • the compressive strength data also indicates that wellbore treating fluids comprising zeolite and water, such as the settable spotting fluids of Spots 2 - 6, develop compressive strengths that are suitable for use with wellbore applications in which conventional settable spotting fluids are used.
  • the compressive strength data also illustrates that settable spotting fluids comprising zeolite and water develop an early compressive strength, which increases over time. This illustrates that the zeolite will set, and is a satisfactory substitute for settable material, such as blast furnace slag, fly ash and other hydraulic materials, used in conventional settable spotting fluids.
  • setting of the zeolite was caused by the lime, also known as calcium hydroxide, which is a known activator for converting settable material in conventional settable spotting fluids.
  • an activator such as lime
  • zeolite such as the settable spotting fluids illustrated herein
  • the activator causes the zeolite to set.
  • Contact between an activator and a settable material can be accomplished by various methods well known to those of ordinary skill in the art.
  • the addition of the lime and zeolite together in a settable spotting fluid as described in this example simulates two of the various methods suitable for bringing an activator into contact with the zeolite.
  • zeolite from wellbore treating fluids such as the settable spotting fluids illustrated herein, remains on the walls of the wellbore as part of the filter cake, and/or in permeable areas affecting the wellbore, such as fissures, fractures, caverns, vugs, thief zones, low pressure subterranean zones or high pressure subterranean zones, even if subsequent washes or spacer fluids are used to displace the wellbore treating fluid.
  • An activator is brought into contact with the zeolite remaining in the wellbore by circulation of a subsequent composition, such as a drilling fluid, pill, spotting fluid or other mud, which contains the activator.
  • an activator is brought into contact with the zeolite remaining in the wellbore by diffusion of an activator contained in a cement slurry that is subsequently pumped into the wellbore during primary cementing operations.
  • the two methods simulated by this example are exemplary only, as a variety of methods for bringing a settable material into contact with an activator, which are well known to those of ordinary skill in the art, are suitable for use with the present embodiments.
  • Example 2 illustrates yet another method.
  • Example 2 Three settable spotting fluids (Spots 1, 2, and 3) were prepared by combining the components as set forth in TABLE 2A below.
  • the zeolite, hydrated lime, and retarder were dry-mixed by hand in a glass jar. This dry mix was then added over a 15 second period to a carrier fluid being maintained in a Waring blender at 4,000 RPM. The blender speed was then increased to 12,000 RPM and mixing was continued for 35 seconds.
  • the carrier fluid was water.
  • the amount of hydrated lime, retarder and water used to form the settable spotting fluid is reported in the table as a "% bwoZ", which indicates a weight percent based on the weight of the zeolite, chabazite, which is commercially available from C2C Zeolite Corporation of Calgary, Canada, was used as the zeolite.
  • the retarder comprised a 2/1 lignosulfonate/tartaric acid solution, which is commercially available under the tradename HR-13L from Halliburton Energy Services, Duncan, Oklahoma. TABLE 2A
  • each of Spots 1, 2 and 3 were then tested at the temperatures and times reported in Table 2B. Up to Day 3, each of Spots 1, 2 and 3 were gelatinous. Thus, the gel strength of each of Spots 1, 2 and 3 was measured according to API Recommended Practice Standard Procedure for Field Testing Drilling Fluids 13B, Appendix B, Shear Strength Measurement using Shearometer Tube, the entire disclosure of which is incorporated herein by reference. The test was performed using a Farm® Model 240 Shearometer, available from Farm Instrument Company, Houston, Texas, and operated according to the Farm® Model 240 Shearometer Instruction Card, the entire disclosure of which is incorporated herein by reference.
  • each of Spots 1, 2 and 3 are reported in Table 2 A in pounds per 100 square feet of area ("lb/ 100 ft 2 "). After Spots 1, 2 and 3 turned from gelatinous to solid, the compressive strengths at Days 5 and 6 as reported in Table 2B were determined. The compressive strengths are reported in Table 2B in pounds per square inch (“psi"). To determine the compressive strength, each of Spots 1, 2 and 3 were placed in sealed cylindrical plastic containers, 2 inches in diameter by 4 inches in height. Each plastic container was placed in a water bath at the temperature reported in Table 2B, under atmospheric pressure, for the time periods reported in Table 2B. Each plastic container was then removed from the water bath, allowed to cool, and the cylindrical samples were demolded. The top end of each cylindrical sample was cut using a tile saw to give a smooth and level surface. The remainder of the sample was then placed in a Tinius Olsen universal testing machine and the compressive strength determined according to operating procedures for the universal testing machine. TABLE 2B
  • the gel strength and compressive strength data indicates that wellbore treating fluids
  • zeolite comprising zeolite, water, at least one activator and at least one retarder, such as the settable spotting fluid illustrated in Table 2 A, develop strength over time at a range of temperatures.
  • the identity of the activators), zeolite, retarder(s) and carrier fluid(s) may influence the amount of activator necessary to cause the settable spotting fluid to set, as well as the amount of retarder necessary to slow the set. Accordingly, the amount of activator used in practicing the present embodiments is described as a compressive strength-developing amount.
  • the amount of retarder can be adjusted up or down to control the amount of time it takes for the settable spotting fluid to develop strength.
  • Those of ordinary skill in the art can determine a desirable time to achieve a set, and through the exercise of routine experimentation, determine the amount of retarder necessary to achieve a set over the desired period of time. Accordingly, the amounts of activator, zeolite, retarder and carrier fluid as listed in Example 2 are merely an exemplary embodiment.
  • the activator i.e., the lime
  • the retarder slowed the set so that setting occurred over time.
  • the present embodiments provide a method for performing drilling operations wherein a wellbore treating fluid comprising zeolite, such as the settable spotting fluids illustrated by Examples 1 and 2, at least partially displaces a mud used to drill a wellbore.
  • a wellbore treating fluid comprising zeolite, such as the settable spotting fluids illustrated by Examples 1 and 2
  • the mud is displaced by the settable spotting fluid comprising zeolite before the mud has had an opportunity to develop a gel strength significant enough to make its displacement difficult.
  • a cement slurry may then be pumped into the annulus.
  • any wellbore treating fluids such as drilling, completion and stimulation fluids including, but not limited to, drilling muds, cement compositions, remedial compositions, well cleanup fluids, workover fluids, spacer fluids, gravel pack fluids, acidizing fluids, fracturing fluids, conformance fluids and the like can be prepared using zeolite and a carrier fluid.
  • improved methods of the present invention comprise preparing a wellbore treating fluid using at least one carrier fluid and zeolite, as previously described herein, and placing the fluid in a subterranean formation.
  • Other methods according to the present embodiments include performing drilling operations, completing and/or stimulating a subterranean formation, and performing primary cementing operations using a wellbore treating fluid comprising zeolite and at least one carrier fluid.
  • Other embodiments of the current invention will be apparent to those skilled in the art from a consideration of this specification or practice of the invention disclosed herein. However, the foregoing specification is considered merely exemplary of the current invention with the true scope and spirit of the invention being indicated by the following claims.

Abstract

Methods and compositions for wellbore treating fluids, especially settable spotting fluids, that include zeolite and at least one carrier fluid.

Description

Zeolite-Containing Settable Spotting Fluids Background The present embodiments relate generally to wellbore treating fluids introduced into a subterranean zone penetrated by a wellbore, particularly wellbore treating fluids introduced as settable spotting fluids. Conventionally, a wellbore is drilled using a drilling fluid that is continuously circulated down a drill pipe, through a drill bit, and upwardly through the wellbore to the surface. Typically, after a wellbore has been drilled to total depth, the drill bit is withdrawn from the wellbore, and circulation of the drilling fluid is stopped, thereby initiating a shutdown period. During the shutdown period, the drilling fluid is typically left in the wellbore, and a filter cake of solids from the drilling fluid, and additional dehydrated drilling fluid and gelled drilling fluid, typically forms on the walls of the wellbore. The next operation in completing the wellbore usually involves running a pipe string, e.g., casing, into the wellbore. While the pipe is being run, the drilling fluid left in the wellbore remains relatively static. During that time, the stagnant drilling fluid progressively increases in gel strength, whereby portions of the drilling fluid in the wellbore can become increasingly difficult to displace during subsequent clean-up operations. After the pipe is run in the wellbore, the next operation typically involves cleaning out the wellbore, which may be accomplished by re-initiating circulation of drilling fluid. The drilling fluid is circulated downwardly through the interior of the pipe and upwardly through the annulus between the exterior of the pipe and the walls of the wellbore, while removing drilling solids, gas, filter cake, dehydrated drilling fluid, gelled drilling fluid, and any other undesired substances needing to be removed from the wellbore. After clean-up operations are performed in the wellbore, primary cementing operations are typically performed therein. Namely, the pipe is cemented in the wellbore by placing a cement slurry in the annulus between the pipe and the walls of the wellbore. The cement slurry sets into a hard impermeable mass, and is intended to bond the pipe to the walls of the wellbore whereby the annulus is sealed and fluid communication between subterranean zones or to the surface by way of the annulus is prevented. During any of the above or other operations performed in the wellbore, a number of problems can occur, including difficulty in removing portions of the drilling fluid, or inability to achieve a satisfactory bond between the pipe and the walls of the wellbore because of drilling fluid that remained in the wellbore during primary cementing operations. Difficulty in removing portions of the drilling fluid is often caused by an increase in the gel strength of the drilling fluid, which is often due to the amount of time the drilling fluid has been left stagnant in the wellbore. In addition, polymeric viscosifiers and additives in the drilling fluid contribute to the formation of a filter cake that is generally very stable and can be difficult to remove. If appreciable drilling fluid and/or filter cake remain in the wellbore or on the walls of the wellbore, a satisfactory bond between the pipe, primary cement and the walls of the wellbore will not be achieved, which can lead to fluid leakage through the annulus and other problems. Removal of the drilling fluid and filter cake from the wellbore is often attempted by running flushes, washes or spacer fluids through the annulus between the pipe and the walls of the wellbore prior to cementing. Other methods for removing drilling fluid and preventing filter cake from interfering with subsequent primary cementing operations include at least partially displacing the drilling fluid with a settable spotting fluid composition (also referred to as a "settable spotting fluid") before the drilling fluid in the wellbore has had a chance to gain significant gel strength. Conventional settable spotting fluids include a material that sets over time, such as blast furnace slag, fly ash, and similar hydraulic components. Still other methods for achieving satisfactory primary cementing operations when deposits of filter cake are an issue include laying down a filter cake including a settable material on the walls of the wellbore and activating the settable material to set. The present embodiments provide wellbore treating fluids in the form of settable spotting fluids that include zeolite as a settable material, and methods for causing the zeolite to set and using such settable spotting fluids in drilling operations. Description According to embodiments described herein, wellbore treating fluids comprising zeolite are introduced into a wellbore in the form of a settable spotting fluid. Methods according to the present embodiments provide for introducing a wellbore treating fluid comprising zeolite into a wellbore penetrating a subterranean zone, introducing a subsequent composition comprising a compressive strength-developing amount of an activator into the wellbore to displace all but a remaining portion of the wellbore treating fluid from the wellbore, contacting the zeolite in the remaining portion of the wellbore treating fluid with the activator, and allowing the zeolite to set. Other methods according to the present embodiments provide for introducing a wellbore treating fluid comprising zeolite, a compressive strength-developing amount of an activator, and a retarder, into a wellbore penetrating a subterranean zone, introducing a subsequent composition into the wellbore to displace all but a remaining portion of the wellbore treating fluid from the wellbore, and allowing the zeolite in the remaining portion of the wellbore treating fluid to set. Setting of the zeolite according to the present embodiments is similar to the setting of settable materials in conventional settable spotting fluids, that is, the zeolite sets into a relatively hard mass. The compressive strength of the set mass formed by the zeolite can be measured and compared to compressive strengths of set materials in conventional settable spotting fluids. In practicing methods according to the present embodiments, drilling fluid (also referred to herein as "mud") remaining in a wellbore during a shutdown period is at least partially displaced with a settable spotting fluid comprising zeolite. Preferably, the mud in the wellbore is displaced with the settable spotting fluid before the mud has had a chance to gain significant gel strength. By displacing the mud before it gains significant gel strength, difficulties with removing portions of it during clean-up operations in the wellbore are reduced. As used herein, the term "mud" encompasses any fluid used in hydrocarbon drilling operations, including but not limited to all types of water-base, oil-base and synthetic-base drilling fluids, and fluids that contain significant amounts of suspended solids, emulsified water or oil. According to one embodiment where a settable spotting fluid comprising zeolite at least partially displaces mud from the wellbore, the settable spotting fluid is subsequently flushed out of the wellbore by washes or spacer fluids circulated through the wellbore. A cement slurry may then be pumped into the annulus and allowed to set, thus bonding the pipe to the walls of the wellbore. The setting of the cement, and consequently the bonding of the pipe to the walls of the wellbore, is improved because difficulties with removing portions of the mud from the wellbore are reduced. According to another embodiment where a settable spotting fluid comprising zeolite at least partially displaces mud from a wellbore, portions of the settable spotting fluid remain on the walls of the wellbore as part of the filter cake, and/or in permeable areas affecting the wellbore, such as fissures, fractures, caverns, vugs, thief zones, low pressure subterranean zones or high pressure subterranean zones, even if washes or spacer fluids are introduced into the wellbore subsequent to the settable spotting fluid. According to such an embodiment, a subsequent composition, for example, a drilling fluid, pill, spotting fluid or other mud, which contains at least one activator, is pumped into the wellbore. The subsequent composition is pumped into the wellbore, either after the settable spotting fluid, or after the washes or spacer fluids, if such are used. When the activator in the subsequent composition contacts the settable spotting fluid remaining in the filter cake and/or permeable areas, the activator causes the zeolite therein to set. The activator is present in the subsequent composition in a compressive strength-developing amount, and may be one or more of calcium hydroxide, sodium silicate, sodium fluoride, sodium silicofluoride, magnesium silicofluoride, zinc silicofluoride, sodium carbonate, potassium carbonate, sodium hydroxide, potassium hydroxide, sodium sulfate, and mixtures thereof. Selection of the type and amount of an activator(s) largely depends on the type and make-up of the composition in which the activator is contained, and it is within the means of those of ordinary skill in the art to select a suitable type and amount of activator. According to yet another embodiment where portions of a settable spotting fluid comprising zeolite remain on the walls of the wellbore as part of the filter cake, and/or in permeable areas affecting the wellbore, primary cementing operations are performed by introducing a cement slurry containing at least one activator into the wellbore. The cement slurry can be introduced after the settable spotting fluid to displace the settable spotting fluid from the wellbore, or can be introduced after a wash or spacer fluid that was pumped into the wellbore after the settable spotting fluid. As the cement slurry is pumped, and as it begins to set in the wellbore, the activator therein diffuses into the settable spotting fluid remaining in the filter cake and/or permeable areas, and causes the zeolite to set. The activator is present in the cement slurry in a compressive strength-developing amount, and may be one or more of calcium hydroxide, sodium silicate, sodium fluoride, sodium silicofluoride, magnesium silicofluoride, zinc silicofluoride, sodium carbonate, potassium carbonate, sodium hydroxide, potassium hydroxide, sodium sulfate, and mixtures thereof. Selection of the type and amount of an activator(s) largely depends on the nature and composition of the cement slurry, and it is within the means of those of ordinary skill in the art to select a suitable type and amount of activator. According to yet another embodiment, a settable spotting fluid comprising zeolite, a compressive strength-developing amount of at least one activator and at least one retarder is introduced into a wellbore. Portions of the settable spotting fluid remain on the walls of the wellbore as part of the filter cake, and/or in permeable areas affecting the wellbore, even if washes or spacer fluids are introduced into the wellbore subsequent to the settable spotting fluid. The activator in the settable spotting fluid causes the zeolite in the remaining portions to set, while the retarder slows the set so that it occurs over a desired period of time. According to such an embodiment, other drilling operations can proceed, which operations may require other muds, fluids, or compositions to be subsequently pumped into the wellbore. If subsequent muds, fluids, or compositions are pumped into the wellbore, they may or may not comprise an activator. As above, the activator in the settable spotting fluid may be one or more of calcium hydroxide, sodium silicate, sodium fluoride, sodium silicofluoride, magnesium silicofluoride, zinc silicofluoride, sodium carbonate, potassium carbonate, sodium hydroxide, potassium hydroxide, sodium sulfate, and mixtures thereof. Suitable retarders include but are not limited to one or more of a lignosulfonate, an organic acid having an α-hydroxy group such as citric acid, tartaric acid or gluconic acid, and combinations of both lignosulfonate and organic acid having an α-hydroxy group.
Selection of the type and amount of activators) and retarder(s) largely depends on the nature and composition of the settable spotting fluid, and it is within the means of those of ordinary skill in the art to select a suitable type and amount of activator and retarder. Moreover, it is within the means of those of ordinary skill in the art to exert control over the amount of time that it takes the zeolite to set by determining, through the exercise of routine experimentation, the amount of retarder necessary to achieve a set over a desired period of time. Thus, in addition to reducing difficulties with removing drilling fluid during clean-up operations, a settable spotting fluid comprising zeolite also provides a method by which zeolite remaining in the wellbore after displacement of the settable spotting fluid can be caused to set. Zeolite that sets in permeable areas affecting the wellbore, such as fissures, fractures, caverns, vugs, thief zones, low pressure subterranean zones or high pressure subterranean zones effectively seals such permeable areas, thereby preventing the entry or flow of formation fluids into the annulus. Zeolites are porous alumino-silicate minerals that may be either a natural or manmade material. Manmade zeolites are based on the same type of structural cell as natural zeolites, and are composed of aluminosilicate hydrates having the same basic formula as given below. It is understood that as used in this application, the term "zeolite" means and encompasses all natural and manmade forms of zeolites. All zeolites are composed of a three-dimensional framework of SiO4 and AlO4 in a tetrahedron, which creates a very high surface area. Cations and water molecules are entrained into the framework. Thus, all zeolites may be represented by the crystallographic unit cell formula: Ma/n[(AlO2)a(SiO2)b] - xH2O where M represents one or more cations such as Na, K, Mg, Ca, Sr, Li or Ba for natural zeolites and NH,, CH3NH3, (CH3)3NH, (CH3)4N, Ga, Ge and P for manmade zeolites; n represents the cation valence; the ratio of b:a is in a range from greater than or equal to 1 and less than or equal to 5; and x represents the moles of water entrained into the zeolite framework. Preferred zeolites for use in the wellbore treating fluids of the present embodiments include analcime (hydrated sodium aluminum silicate), bikitaite (lithium aluminum silicate), brewsterite (hydrated strontium barium calcium aluminum silicate), chabazite (hydrated calcium aluminum silicate), clinoptilolite (hydrated sodium aluminum silicate), faujasite (hydrated sodium potassium calcium magnesium aluminum silicate), harmotome (hydrated barium aluminum silicate), heulandite (hydrated sodium calcium aluminum silicate), laumontite (hydrated calcium aluminum silicate), mesolite (hydrated sodium calcium aluminum silicate), natrolite (hydrated sodium aluminum silicate), paulingite (hydrated potassium sodium calcium barium aluminum silicate), phillipsite (hydrated potassium sodium calcium aluminum silicate), scolecite (hydrated calcium aluminum silicate), stellerite (hydrated calcium aluminum silicate), stilbite (hydrated sodium calcium aluminum silicate) and thomsonite (hydrated sodium calcium aluminum silicate). Most preferably, the zeolites for use in the wellbore treating fluids of the present embodiment include chabazite and clinoptilolite. Carrier fluids suitable for use in the embodiments of wellbore treating fluids, such as settable spotting fluids disclosed herein, comprise aqueous fluids, oil-based and synthetic- based fluids, emulsion, acids, or mixtures thereof. Exemplary aqueous fluids include but are not limited to water and water-based gels. When the carrier fluid comprises water, the water can be fresh water, imsaturated salt solution, including brines and seawater, and saturated salt solution. Exemplary oil-based fluids include but are not limited to canola oil, kerosene, diesel oil, fish oil, mineral oil, sunflower oil, corn oil, soy oil, olive oil, cottonseed oil, peanut oil and paraffin. Exemplary synthetic-based fluids include but are not limited to esters, olefins and ethers. The preferred carrier fluid for the wellbore treating fluid comprising zeolite as disclosed herein depends upon the properties desired for the wellbore treating fluid, as well as the cost, availability, temperature, stability, viscosity, clarity, and the like of the carrier fluid. According to one embodiment, a settable spotting fluid comprising zeolite is prepared by mixing an amount of zeolite with a carrier fluid in an amount of from about 100 to about 200 weight percent, based on the weight of the amount of zeolite. According to embodiments where a settable spotting fluid comprising zeolite at least partially displaces a mud, the mud can be a water-based drilling fluid, an oil-based drilling fluid, or a synthetic- based drilling fluid. In carrying out the methods of the present embodiments, a wellbore treating fluid comprising zeolite and at least one carrier fluid is introduced into a wellbore to at least partially displace a mud from the wellbore. A subsequent composition is introduced into the wellbore to displace all but a remaining portion of the wellbore treating fluid from the wellbore. The zeolite in the remaining portion of the wellbore treating fluid sets into a relatively hard mass. Displacement of the mud from the wellbore and setting of zeolite remaining in the wellbore contribute to the creation of satisfactory conditions for primary cementing operations. In addition, setting of zeolite that remained in one or more permeable areas affecting the wellbore, such as fissures, fractures, caverns, vugs, thief zones, low pressure subterranean zones or high pressure subterranean zones effectively seals such permeable areas, thereby preventing the entry or flow of formation fluids into the annulus. The following examples are illustrative of the foregoing methods and compositions. EXAMPLE 1 Six settable spotting fluids ("Spots") were prepared by combining the components as set forth in TABLE 1 below. Specifically, the zeolite and the hydrated lime were dry-mixed by hand in a glass jar. This dry mix was then added over a 15 second period to a carrier fluid being maintained in a Waring blender at 4,000 RPM. The blender speed was then increased to 12,000 RPM and mixing was continued for 35 seconds. According to the embodiments illustrated in Table 1, the carrier fluid was water. The amount of hydrated lime and water used to form each settable spotting fluid is reported in the table as a "% bwoZ", which indicates a weight percent based on the weight of the zeolite. Chabazite was used as the zeolite for Spots 1 - 4, and clinoptilolite was used as the zeolite for Spots 5 - 6. Each of these zeolites is commercially available from C2C Zeolite Corporation of Calgary, Canada. The compressive strength for each of Spots 1 - 6 was determined by Non-Destructive Sonic Testing as set forth in API Specification 10B 22nd Edition, 1997, of the American Petroleum Institute, the entire disclosure of which is incorporated herein by reference as if reproduced in its entirety. As reported in Table 1, the compressive strength was measured at 160°F at the reported elapsed times. The measured compressive strength is reported in Table 1 in pounds per square inch (psi).
TABLE 1
Figure imgf000010_0001
The compressive strength data indicates that wellbore treating fluids comprising zeolite and water, such as the settable spotting fluids illustrated in Example 1, develop compressive strengths when the amount of an activator, such as lime, is present in an amount greater than about 7% based on the weight of the zeolite. The identity of the activator, zeolite, and carrier fluid may influence the amount of activator necessary to cause the settable spotting fluid to set; thus, in some embodiments, the settable spotting fluid may develop compressive strength with activator amounts less than the 7% illustrated by Example 1. Accordingly, the amount of activator used in practicing the present embodiments need only be at least a compressive strength-developing amount. Those of ordinary skill in the art can determine through the exercise of routine experimentation the amount of an activator sufficient for the development of compressive strength. The compressive strength data also indicates that wellbore treating fluids comprising zeolite and water, such as the settable spotting fluids of Spots 2 - 6, develop compressive strengths that are suitable for use with wellbore applications in which conventional settable spotting fluids are used. The compressive strength data also illustrates that settable spotting fluids comprising zeolite and water develop an early compressive strength, which increases over time. This illustrates that the zeolite will set, and is a satisfactory substitute for settable material, such as blast furnace slag, fly ash and other hydraulic materials, used in conventional settable spotting fluids. In the settable spotting fluids of Example 1, setting of the zeolite was caused by the lime, also known as calcium hydroxide, which is a known activator for converting settable material in conventional settable spotting fluids. Thus, when an activator, such as lime, is brought into contact with a wellbore treating fluid comprising zeolite, such as the settable spotting fluids illustrated herein, the activator causes the zeolite to set. Contact between an activator and a settable material can be accomplished by various methods well known to those of ordinary skill in the art. The addition of the lime and zeolite together in a settable spotting fluid as described in this example simulates two of the various methods suitable for bringing an activator into contact with the zeolite. According to the first method simulated by this example, zeolite from wellbore treating fluids, such as the settable spotting fluids illustrated herein, remains on the walls of the wellbore as part of the filter cake, and/or in permeable areas affecting the wellbore, such as fissures, fractures, caverns, vugs, thief zones, low pressure subterranean zones or high pressure subterranean zones, even if subsequent washes or spacer fluids are used to displace the wellbore treating fluid. An activator is brought into contact with the zeolite remaining in the wellbore by circulation of a subsequent composition, such as a drilling fluid, pill, spotting fluid or other mud, which contains the activator. According to the second method simulated by this example, an activator is brought into contact with the zeolite remaining in the wellbore by diffusion of an activator contained in a cement slurry that is subsequently pumped into the wellbore during primary cementing operations. The two methods simulated by this example are exemplary only, as a variety of methods for bringing a settable material into contact with an activator, which are well known to those of ordinary skill in the art, are suitable for use with the present embodiments. Example 2 illustrates yet another method. Example 2 Three settable spotting fluids (Spots 1, 2, and 3) were prepared by combining the components as set forth in TABLE 2A below. Specifically, the zeolite, hydrated lime, and retarder were dry-mixed by hand in a glass jar. This dry mix was then added over a 15 second period to a carrier fluid being maintained in a Waring blender at 4,000 RPM. The blender speed was then increased to 12,000 RPM and mixing was continued for 35 seconds. According to the embodiment illustrated in Table 2A, the carrier fluid was water. The amount of hydrated lime, retarder and water used to form the settable spotting fluid is reported in the table as a "% bwoZ", which indicates a weight percent based on the weight of the zeolite, chabazite, which is commercially available from C2C Zeolite Corporation of Calgary, Canada, was used as the zeolite. The retarder comprised a 2/1 lignosulfonate/tartaric acid solution, which is commercially available under the tradename HR-13L from Halliburton Energy Services, Duncan, Oklahoma. TABLE 2A
Figure imgf000012_0001
The strengths of each of Spots 1, 2 and 3 were then tested at the temperatures and times reported in Table 2B. Up to Day 3, each of Spots 1, 2 and 3 were gelatinous. Thus, the gel strength of each of Spots 1, 2 and 3 was measured according to API Recommended Practice Standard Procedure for Field Testing Drilling Fluids 13B, Appendix B, Shear Strength Measurement using Shearometer Tube, the entire disclosure of which is incorporated herein by reference. The test was performed using a Farm® Model 240 Shearometer, available from Farm Instrument Company, Houston, Texas, and operated according to the Farm® Model 240 Shearometer Instruction Card, the entire disclosure of which is incorporated herein by reference. The gel strength of each of Spots 1, 2 and 3 are reported in Table 2 A in pounds per 100 square feet of area ("lb/ 100 ft2"). After Spots 1, 2 and 3 turned from gelatinous to solid, the compressive strengths at Days 5 and 6 as reported in Table 2B were determined. The compressive strengths are reported in Table 2B in pounds per square inch ("psi"). To determine the compressive strength, each of Spots 1, 2 and 3 were placed in sealed cylindrical plastic containers, 2 inches in diameter by 4 inches in height. Each plastic container was placed in a water bath at the temperature reported in Table 2B, under atmospheric pressure, for the time periods reported in Table 2B. Each plastic container was then removed from the water bath, allowed to cool, and the cylindrical samples were demolded. The top end of each cylindrical sample was cut using a tile saw to give a smooth and level surface. The remainder of the sample was then placed in a Tinius Olsen universal testing machine and the compressive strength determined according to operating procedures for the universal testing machine. TABLE 2B
Figure imgf000013_0001
The gel strength and compressive strength data indicates that wellbore treating fluids
comprising zeolite, water, at least one activator and at least one retarder, such as the settable spotting fluid illustrated in Table 2 A, develop strength over time at a range of temperatures. This illustrates that the zeolite will set, and is a satisfactory substitute for settable material, such as blast furnace slag, fly ash and other hydraulic materials, used in conventional settable spotting fluids. The identity of the activators), zeolite, retarder(s) and carrier fluid(s) may influence the amount of activator necessary to cause the settable spotting fluid to set, as well as the amount of retarder necessary to slow the set. Accordingly, the amount of activator used in practicing the present embodiments is described as a compressive strength-developing amount. Moreover, the amount of retarder can be adjusted up or down to control the amount of time it takes for the settable spotting fluid to develop strength. Those of ordinary skill in the art can determine a desirable time to achieve a set, and through the exercise of routine experimentation, determine the amount of retarder necessary to achieve a set over the desired period of time. Accordingly, the amounts of activator, zeolite, retarder and carrier fluid as listed in Example 2 are merely an exemplary embodiment. In the settable spotting fluid illustrated in Example 2, the activator (i.e., the lime) caused the zeolite to set, while the retarder slowed the set so that setting occurred over time. This illustrates yet another method for bringing an activator into contact with the zeolite in portions of settable spotting fluid that remains in the wellbore. Moreover, the present embodiments provide a method for performing drilling operations wherein a wellbore treating fluid comprising zeolite, such as the settable spotting fluids illustrated by Examples 1 and 2, at least partially displaces a mud used to drill a wellbore. Preferably, the mud is displaced by the settable spotting fluid comprising zeolite before the mud has had an opportunity to develop a gel strength significant enough to make its displacement difficult. After the mud is at least partially displaced by the settable spotting fluid, a cement slurry may then be pumped into the annulus. The cement slurry is allowed to set, thus bonding the pipe to the walls of the wellbore. The setting of the cement, and consequently the bonding of the pipe to the walls of the wellbore, is improved because difficulties with removing portions of the drilling fluid in the wellbore are reduced. While the embodiments described herein relate to wellbore treating fluids provided as settable spotting fluids, it is understood that any wellbore treating fluids such as drilling, completion and stimulation fluids including, but not limited to, drilling muds, cement compositions, remedial compositions, well cleanup fluids, workover fluids, spacer fluids, gravel pack fluids, acidizing fluids, fracturing fluids, conformance fluids and the like can be prepared using zeolite and a carrier fluid. Accordingly, improved methods of the present invention comprise preparing a wellbore treating fluid using at least one carrier fluid and zeolite, as previously described herein, and placing the fluid in a subterranean formation. Other methods according to the present embodiments include performing drilling operations, completing and/or stimulating a subterranean formation, and performing primary cementing operations using a wellbore treating fluid comprising zeolite and at least one carrier fluid. Other embodiments of the current invention will be apparent to those skilled in the art from a consideration of this specification or practice of the invention disclosed herein. However, the foregoing specification is considered merely exemplary of the current invention with the true scope and spirit of the invention being indicated by the following claims.

Claims

What is claimed is:
1. A method of performing drilling operations comprising the steps of: penetrating a subterranean zone with a wellbore; introducing a wellbore treating fluid comprising zeolite and at least one carrier fluid into the wellbore; introducing a subsequent composition comprising a compressive strength-developing amount of at least one activator into the wellbore to displace all but a remaining portion of the wellbore treating fluid from the wellbore; and contacting the zeolite in the remaining portion of the wellbore treating fluid with the at least one activator.
2. The method of claim 1 further comprising: allowing the zeolite in the remaining portion of the wellbore treating fluid to set.
3. The method of claim 1 wherein the remaining portion of the wellbore treating fluid is in one or more of a filter cake, fissure, fracture, cavern, vug, thief zone, low pressure subterranean zone, and high pressure subterranean zone in the wellbore.
4. The method of claim 3 further comprising: allowing the zeolite in the remaining portion of the wellbore treating fluid to set, wherein the set zeolite seals one or more of a fissure, fracture, cavern, vug, thief zone, low pressure subterranean zone, and high pressure subterranean zone in the wellbore.
5. The method of claim 1 wherein the penetrating of the subterranean zone with a wellbore comprises drilling the wellbore with a mud, and wherein the introducing of the wellbore treating fluid at least partially displaces the mud from the wellbore.
6. The method of claim 1 wherein the introducing of the subsequent composition comprises: introducing a drilling fluid comprising a compressive strength-developing amount of at least one activator into the wellbore.
7. The method of claim 6 wherein the at least one activator is selected from the group consisting of calcium hydroxide, sodium silicate, sodium fluoride, sodium silicofluoride, magnesium silicofluoride, zinc silicofluoride, sodium carbonate, potassium carbonate, sodium hydroxide, potassium hydroxide, sodium sulfate, and mixtures thereof.
8. The method of claim 6 further comprising placing a cement slurry in the wellbore after the introducing of the drilling fluid.
9. The method of claim 1 wherein the introducing of the subsequent composition comprises: introducing a cement slurry comprising a compressive strength-developing amount of at least one activator into the wellbore; and allowing the at least one activator to diffuse into contact with the zeolite in the remaining portion of the wellbore treating fluid.
10. The method of claim 9 wherein the at least one activator is selected from the group consisting of calcium hydroxide, sodium silicate, sodium fluoride, sodium silicofluoride, magnesium silicofluoride, zinc silicofluoride, sodium carbonate, potassium carbonate, sodium hydroxide, potassium hydroxide, sodium sulfate, and mixtures thereof.
11. The method of claim 1 wherein the introducing of the subsequent composition comprises: introducing at least one of a mud, a spotting fluid, a pill and a cement slurry comprising a compressive strength-developing amount of at least one activator into the wellbore.
12. The method of claim 11 wherein the at least one activator is selected from the group consisting of calcium hydroxide, sodium silicate, sodium fluoride, sodium silicofluoride, magnesium silicofluoride, zinc silicofluoride, sodium carbonate, potassium carbonate, sodium hydroxide, potassium hydroxide, sodium sulfate, and mixtures thereof.
13. The method of claim 1 wherein the zeolite is represented by the formula: Ma/n[(AlO2)a(SiO2)b] - xH2O where M represents one or more cations selected from the group consisting of Na, K, Mg, Ca, Sr, Li, Ba,NH4, CH3NH3, (CH3)3NH, (CH3)4N, Ga, Ge and P; n represents the cation valence; the ratio of b:a is in a range from greater than or equal to 1 and less than or equal to 5; and x represents the moles of water entrained into the zeolite framework.
14. The method of claim 1, wherein the zeolite is selected from the group consisting of analcime, bikitaite, brewsterite, chabazite, clinoptilolite, faujasite, harmotome, heulandite, laumontite, mesolite, natrolite, paulingite, phillipsite, scolecite, stellerite, stilbite, and thomsonite.
15. The method of claim 1 wherein the at least one carrier fluid comprises a water-based carrier fluid in an amount of from about 100 to about 200 percent by weight of the zeolite.
16. The method of claim 1 wherein the at least one carrier fluid is selected from the group consisting of water and water-based gels.
17. The method of claim 1 wherein the at least one carrier fluid is selected from the group consisting of fresh water, unsaturated salt solution, brine, seawater, and saturated salt solution.
18. The method of claim 1 wherein the at least one carrier fluid comprises an oil-based fluid selected from the group consisting of canola oil, kerosene, diesel oil, fish oil, mineral oil, sunflower oil, corn oil, soy oil, olive oil, cottonseed oil, peanut oil and paraffin.
19. A method of performing drilling operations comprising the steps of: penetrating a subterranean zone with a wellbore; introducing a wellbore treating fluid comprising zeolite, a compressive strength- developing amount of at least one activator, at least one retarder and at least one carrier fluid into the wellbore; and introducing a subsequent composition into the wellbore to displace all but a remaining portion of the wellbore treating fluid from the wellbore.
20. The method of claim 19 further comprising: allowing the zeolite in the remaining portion of the wellbore treating fluid to set.
21. The method of claim 19 wherein the remaining portion of the wellbore treating fluid is in one or more of a filter cake, fissure, fracture, cavern, vug, thief zone, low pressure subterranean zone, and high pressure subterranean zone in the wellbore.
22. The method of claim 21 further comprising: allowing the zeolite in the remaining portion of the wellbore treating fluid to set, wherein the set zeolite seals one or more of a fissure, fracture, cavern, vug, thief zone, low pressure subterranean zone, and high pressure subterranean zone in the wellbore.
23. The method of claim 19 wherein the penetrating of the subterranean zone with a wellbore comprises drilling the wellbore with a mud, and wherein the introducing of the wellbore treating fluid at least partially displaces the mud from the wellbore.
24. The method of claim 19 wherein the at least one activator is selected from the group consisting of calcium hydroxide, sodium silicate, sodium fluoride, sodium silicofluoride, magnesium silicofluoride, zinc silicofluoride, sodium carbonate, potassium carbonate, sodium hydroxide, potassium hydroxide, sodium sulfate, and mixtures thereof.
25. The method of claim 19 wherein the at least one retarder is selected from the group consisting of lignosulfonates, citric acids, tartaric acids, gluconic acids, organic acids having an α-hydroxy group, and combinations thereof.
26. The method of claim 19 further comprising placing a cement slurry in the wellbore after the introducing of the subsequent composition.
27. The method of claim 19 wherein the introducing of the subsequent composition comprises introducing at least one of a mud, a spotting fluid, a pill and a cement slurry into the wellbore.
28. The method of claim 27 wherein the subsequent composition comprises at least one activator.
29. The method of claim 28 wherein the at least one activator is selected from the group consisting of calcium hydroxide, sodium silicate, sodium fluoride, sodium silicofluoride, magnesium silicofluoride, zinc silicofluoride, sodium carbonate, potassium carbonate, sodium hydroxide, potassium hydroxide, sodium sulfate, and mixtures thereof.
30. The method of claim 19 wherein the zeolite is represented by the formula: JV [(A102)a(Siθ2)b] - xH20 where M represents one or more cations selected from the group consisting of Na, K, Mg, Ca, Sr, Li, Ba,NH4, CH3NH3, (CH3)3NH, (CH3)4N, Ga, Ge and P; n represents the cation valence; the ratio of b:a is in a range from greater than or equal to 1 and less than or equal to 5; and x represents the moles of water entrained into the zeolite framework.
31. The method of claim 19 wherein the zeolite is selected from the group consisting of analcime, bikitaite, brewsterite, chabazite, clinoptilolite, faujasite, harmotome, heulandite, laumontite, mesolite, natrolite, paulingite, phillipsite, scolecite, stellerite, stilbite, and thomsonite.
32. The method of claim 19 wherein the at least one carrier fluid comprises a water-based carrier fluid in an amount of from about 100 to about 200 percent by weight of the zeolite.
33. The method of claim 19 wherein the at least one carrier fluid is selected from the group consisting of water and water-based gels.
34. The method of claim 19 wherein the at least one carrier fluid is selected from the group consisting of fresh water, unsaturated salt solution, brine, seawater, and saturated salt solution.
35. The method of claim 19 wherein the at least one carrier fluid comprises an oil-based fluid selected from the group consisting of canola oil, kerosene, diesel oil, fish oil, mineral oil, sunflower oil, corn oil, soy oil, olive oil, cottonseed oil, peanut oil and paraffin.
36. A method of performing drilling operations comprising the steps of: penetrating a subterranean zone with a wellbore; introducing a wellbore treating fluid comprising zeolite and at least one carrier fluid into the wellbore; introducing a subsequent composition comprising at least one activator into the wellbore to displace all but a remaining portion of the wellbore treating fluid from the wellbore; and contacting the zeolite in the remaining portion of the wellbore treating fluid with the at least one activator.
37. A method of performing drilling operations comprising the steps of: penetrating a subterranean zone with a wellbore; introducing a wellbore treating fluid comprising zeolite, at least one activator, at least one retarder and at least one carrier fluid into the wellbore; and introducing a subsequent composition into the wellbore to displace all but a remaining portion of the wellbore treating fluid from the wellbore.
38. A settable spotting fluid comprising zeolite and at least one carrier fluid.
39. The settable spotting fluid of claim 38 wherein the zeolite is represented by the formula: Ma/nKAlO.USiOΛl - X^O where M represents one or more cations selected from the group consisting of Na, K, Mg, Ca, Sr, Li, Ba,NH,, CH3NH3, (CH3)3NH, (CH3)4N, Ga, Ge and P; n represents the cation valence; the ratio of b:a is in a range from greater than or equal to 1 and less than or equal to 5; and x represents the moles of water entrained into the zeolite framework.
40. The settable spotting fluid of claim 38, wherein the zeolite is selected from the group consisting of analcime, bikitaite, brewsterite, chabazite, clinoptilolite, faujasite, harmotome, heulandite, laumontite, mesolite, natrolite, paulingite, phillipsite, scolecite, stellerite, stilbite, and thomsonite.
41. The settable spotting fluid of claim 38 further comprising at least one activator and at least one retarder.
42. The settable spotting fluid of claim 41 wherein the at least one activator is present in a compressive strength-developing amount.
43. The settable spotting fluid of claim 41 wherein the at least one activator is selected from the group consisting of calcium hydroxide, sodium silicate, sodium fluoride, sodium silicofluoride, magnesium silicofluoride, zinc silicofluoride, sodium carbonate, potassium carbonate, sodium hydroxide, potassium hydroxide, sodium sulfate, and mixtures thereof.
44. The settable spotting fluid of claim 41 wherein the at least one retarder is selected from the group consisting of lignosulfonates, citric acids, tartaric acids, gluconic acids, organic acids having an α-hydroxy group, and combinations thereof.
45. The method of claim 38 wherein the at least one carrier fluid comprises a water-based carrier fluid in an amount of from about 100 to about 200 percent by weight of the zeolite.
46. The method of claim 38 wherein the at least one carrier fluid is selected from the group consisting of water and water-based gels.
47. The method of claim 38 wherein the at least one carrier fluid is selected from the group consisting of fresh water, unsaturated salt solution, brine, seawater, and saturated salt solution.
48. The method of claim 38 wherein the at least one carrier fluid comprises an oil-based fluid selected from the group consisting of canola oil, kerosene, diesel oil, fish oil, mineral oil, sunflower oil, corn oil, soy oil, olive oil, cottonseed oil, peanut oil and paraffin.
PCT/GB2004/004899 2003-12-17 2004-11-19 Zeolite-containing settable spotting fluids WO2005059301A1 (en)

Priority Applications (1)

Application Number Priority Date Filing Date Title
CA002549515A CA2549515C (en) 2003-12-17 2004-11-19 Zeolite-containing settable spotting fluids

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US10/738,199 US7150321B2 (en) 2002-12-10 2003-12-17 Zeolite-containing settable spotting fluids
US10/738,199 2003-12-17

Publications (1)

Publication Number Publication Date
WO2005059301A1 true WO2005059301A1 (en) 2005-06-30

Family

ID=34700465

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/GB2004/004899 WO2005059301A1 (en) 2003-12-17 2004-11-19 Zeolite-containing settable spotting fluids

Country Status (3)

Country Link
US (1) US7150321B2 (en)
CA (1) CA2549515C (en)
WO (1) WO2005059301A1 (en)

Cited By (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2006010879A1 (en) * 2004-07-28 2006-02-02 Halliburton Energy Services, Inc. Cement-free zeolite and fly ash settable fluids and methods therefor
US7219733B2 (en) 2004-09-29 2007-05-22 Halliburton Energy Services, Inc. Zeolite compositions for lowering maximum cementing temperature
JP2008530328A (en) * 2005-02-17 2008-08-07 ビーエーエスエフ ソシエタス・ヨーロピア Formulation of polycondensate

Families Citing this family (56)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US7048053B2 (en) * 2002-12-10 2006-05-23 Halliburton Energy Services, Inc. Zeolite compositions having enhanced compressive strength
US6964302B2 (en) * 2002-12-10 2005-11-15 Halliburton Energy Services, Inc. Zeolite-containing cement composition
US7140439B2 (en) * 2002-12-10 2006-11-28 Halliburton Energy Services, Inc. Zeolite-containing remedial compositions
US6989057B2 (en) * 2002-12-10 2006-01-24 Halliburton Energy Services, Inc. Zeolite-containing cement composition
US7448450B2 (en) * 2003-12-04 2008-11-11 Halliburton Energy Services, Inc. Drilling and cementing with fluids containing zeolite
US7137448B2 (en) * 2003-12-22 2006-11-21 Bj Services Company Method of cementing a well using composition containing zeolite
US7607482B2 (en) 2005-09-09 2009-10-27 Halliburton Energy Services, Inc. Settable compositions comprising cement kiln dust and swellable particles
US9512346B2 (en) 2004-02-10 2016-12-06 Halliburton Energy Services, Inc. Cement compositions and methods utilizing nano-hydraulic cement
US7182137B2 (en) * 2004-09-13 2007-02-27 Halliburton Energy Services, Inc. Cementitious compositions containing interground cement clinker and zeolite
US9512345B2 (en) 2004-10-20 2016-12-06 Halliburton Energy Services, Inc. Settable spacer fluids comprising pumicite and methods of using such fluids in subterranean formations
US20100044057A1 (en) * 2004-10-20 2010-02-25 Dealy Sears T Treatment Fluids Comprising Pumicite and Methods of Using Such Fluids in Subterranean Formations
US7293609B2 (en) * 2004-10-20 2007-11-13 Halliburton Energy Services, Inc. Treatment fluids comprising vitrified shale and methods of using such fluids in subterranean formations
US7341106B2 (en) * 2005-07-21 2008-03-11 Halliburton Energy Services, Inc. Methods for wellbore strengthening and controlling fluid circulation loss
US9150773B2 (en) 2005-09-09 2015-10-06 Halliburton Energy Services, Inc. Compositions comprising kiln dust and wollastonite and methods of use in subterranean formations
US8403045B2 (en) 2005-09-09 2013-03-26 Halliburton Energy Services, Inc. Settable compositions comprising unexpanded perlite and methods of cementing in subterranean formations
US8950486B2 (en) 2005-09-09 2015-02-10 Halliburton Energy Services, Inc. Acid-soluble cement compositions comprising cement kiln dust and methods of use
US8297357B2 (en) 2005-09-09 2012-10-30 Halliburton Energy Services Inc. Acid-soluble cement compositions comprising cement kiln dust and/or a natural pozzolan and methods of use
US8522873B2 (en) 2005-09-09 2013-09-03 Halliburton Energy Services, Inc. Spacer fluids containing cement kiln dust and methods of use
US9023150B2 (en) 2005-09-09 2015-05-05 Halliburton Energy Services, Inc. Acid-soluble cement compositions comprising cement kiln dust and/or a natural pozzolan and methods of use
US8327939B2 (en) 2005-09-09 2012-12-11 Halliburton Energy Services, Inc. Settable compositions comprising cement kiln dust and rice husk ash and methods of use
US7607484B2 (en) 2005-09-09 2009-10-27 Halliburton Energy Services, Inc. Foamed cement compositions comprising oil-swellable particles and methods of use
US8609595B2 (en) 2005-09-09 2013-12-17 Halliburton Energy Services, Inc. Methods for determining reactive index for cement kiln dust, associated compositions, and methods of use
US8672028B2 (en) 2010-12-21 2014-03-18 Halliburton Energy Services, Inc. Settable compositions comprising interground perlite and hydraulic cement
US8505629B2 (en) 2005-09-09 2013-08-13 Halliburton Energy Services, Inc. Foamed spacer fluids containing cement kiln dust and methods of use
US7743828B2 (en) 2005-09-09 2010-06-29 Halliburton Energy Services, Inc. Methods of cementing in subterranean formations using cement kiln cement kiln dust in compositions having reduced Portland cement content
US8307899B2 (en) 2005-09-09 2012-11-13 Halliburton Energy Services, Inc. Methods of plugging and abandoning a well using compositions comprising cement kiln dust and pumicite
US9809737B2 (en) 2005-09-09 2017-11-07 Halliburton Energy Services, Inc. Compositions containing kiln dust and/or biowaste ash and methods of use
US9676989B2 (en) 2005-09-09 2017-06-13 Halliburton Energy Services, Inc. Sealant compositions comprising cement kiln dust and tire-rubber particles and method of use
US8555967B2 (en) 2005-09-09 2013-10-15 Halliburton Energy Services, Inc. Methods and systems for evaluating a boundary between a consolidating spacer fluid and a cement composition
US7478675B2 (en) 2005-09-09 2009-01-20 Halliburton Energy Services, Inc. Extended settable compositions comprising cement kiln dust and associated methods
US9051505B2 (en) 2005-09-09 2015-06-09 Halliburton Energy Services, Inc. Placing a fluid comprising kiln dust in a wellbore through a bottom hole assembly
US7789150B2 (en) 2005-09-09 2010-09-07 Halliburton Energy Services Inc. Latex compositions comprising pozzolan and/or cement kiln dust and methods of use
US9006155B2 (en) 2005-09-09 2015-04-14 Halliburton Energy Services, Inc. Placing a fluid comprising kiln dust in a wellbore through a bottom hole assembly
US8281859B2 (en) 2005-09-09 2012-10-09 Halliburton Energy Services Inc. Methods and compositions comprising cement kiln dust having an altered particle size
US8505630B2 (en) 2005-09-09 2013-08-13 Halliburton Energy Services, Inc. Consolidating spacer fluids and methods of use
US8333240B2 (en) 2005-09-09 2012-12-18 Halliburton Energy Services, Inc. Reduced carbon footprint settable compositions for use in subterranean formations
US20070289720A1 (en) * 2005-12-13 2007-12-20 University Of South Florida Self-Heating Chemical System for Sustained Modulation of Temperature
US7967909B2 (en) * 2007-02-26 2011-06-28 Baker Hughes Incorporated Method of cementing within a gas or oil well
US8685903B2 (en) 2007-05-10 2014-04-01 Halliburton Energy Services, Inc. Lost circulation compositions and associated methods
US8586512B2 (en) 2007-05-10 2013-11-19 Halliburton Energy Services, Inc. Cement compositions and methods utilizing nano-clay
US9206344B2 (en) 2007-05-10 2015-12-08 Halliburton Energy Services, Inc. Sealant compositions and methods utilizing nano-particles
US9512351B2 (en) 2007-05-10 2016-12-06 Halliburton Energy Services, Inc. Well treatment fluids and methods utilizing nano-particles
US9199879B2 (en) 2007-05-10 2015-12-01 Halliburton Energy Serives, Inc. Well treatment compositions and methods utilizing nano-particles
US8476203B2 (en) 2007-05-10 2013-07-02 Halliburton Energy Services, Inc. Cement compositions comprising sub-micron alumina and associated methods
US7740070B2 (en) * 2008-06-16 2010-06-22 Halliburton Energy Services, Inc. Wellbore servicing compositions comprising a density segregation inhibiting composite and methods of making and using same
US9534165B2 (en) 2012-03-09 2017-01-03 Halliburton Energy Services, Inc. Settable compositions and methods of use
US9657214B2 (en) 2014-07-22 2017-05-23 King Fahd University Of Petroleum And Minerals Zero-invasion acidic drilling fluid
US9694400B2 (en) 2015-06-26 2017-07-04 Wildfire Construction Llc Controlled verified remediation of excavated spoil
US10525513B2 (en) 2015-06-26 2020-01-07 Wildfire Construction Llc Construction aggregate from verified remediated spoil
US10683448B2 (en) 2016-02-08 2020-06-16 Saudi Arabian Oil Company Alkyl ester spotting fluid compositions for differential sticking
US11820707B2 (en) 2020-03-18 2023-11-21 Saudi Arabian Oil Company Geopolymer cement slurries, cured geopolymer cement and methods of making and use thereof
US11820708B2 (en) 2020-03-18 2023-11-21 Saudi Arabian Oil Company Geopolymer cement slurries, cured geopolymer cement and methods of making and use thereof
US11015108B1 (en) * 2020-03-18 2021-05-25 Saudi Arabian Oil Company Methods of reducing lost circulation in a wellbore using Saudi Arabian volcanic ash
US11066899B1 (en) 2020-03-18 2021-07-20 Saudi Arabian Oil Company Methods of sealing a subsurface formation with saudi arabian volcanic ash
US10920121B1 (en) 2020-03-18 2021-02-16 Saudi Arabian Oil Company Methods of reducing lost circulation in a wellbore using Saudi Arabian volcanic ash
US11098235B1 (en) 2020-03-18 2021-08-24 Saudi Arabian Oil Company Methods of converting drilling fluids into geopolymer cements and use thereof

Citations (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4888120A (en) * 1986-09-18 1989-12-19 Henkel Kommanditgesellschaft Auf Aktien Water-based drilling and well-servicing fluids with swellable, synthetic layer silicates
JPH073254A (en) * 1991-01-28 1995-01-06 Terunaito:Kk Composition for drilling fluid
EP1428805A1 (en) * 2002-12-10 2004-06-16 Halliburton Energy Services, Inc. Cement composition

Family Cites Families (112)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US1943584A (en) 1929-03-28 1934-01-16 Silica Products Co Inorganic gel composition
US2131338A (en) 1935-12-23 1938-09-27 Philadelphia Quartz Co Consolidation of porous materials
US2094316A (en) 1936-03-06 1937-09-28 Kansas City Testing Lab Method of improving oil well drilling muds
US2349049A (en) 1940-08-03 1944-05-16 Lubri Gel Products Company Salt water drilling mud
US2727001A (en) 1952-12-24 1955-12-13 Sun Oil Co Drilling fluid
US2848051A (en) 1954-03-22 1958-08-19 Atlantic Refining Co Method for improving well cementing jobs
US3047493A (en) 1958-05-26 1962-07-31 Gulf Research Development Co Drilling process and water base drilling muds
US3065170A (en) 1959-07-02 1962-11-20 Jersey Prod Res Co Drilling fluids for use in wells
US3359225A (en) 1963-08-26 1967-12-19 Charles F Weisend Cement additives containing polyvinylpyrrolidone and a condensate of sodium naphthalene sulfonate with formaldehyde
US3293040A (en) 1964-05-25 1966-12-20 American Tansul Company Method for chill-proofing beer with water soluble alkyl cellulose ethers
US3694152A (en) 1968-10-18 1972-09-26 Snam Progetti Process for producing synthetic zeolite
US3888998A (en) 1971-11-22 1975-06-10 Procter & Gamble Beverage carbonation
US3781225A (en) 1972-04-17 1973-12-25 Mobil Oil Corp Treatment of colloidal zeolites
NL7306868A (en) 1973-05-17 1974-11-19
US3884302A (en) 1974-05-29 1975-05-20 Mobil Oil Corp Well cementing process
US3963508A (en) 1974-11-18 1976-06-15 Kaiser Aluminum & Chemical Corporation Calcium aluminate cement
US4054462A (en) 1976-03-01 1977-10-18 The Dow Chemical Company Method of cementing
US4217229A (en) 1976-09-20 1980-08-12 Halliburton Company Oil well spacer fluids
US4141843A (en) 1976-09-20 1979-02-27 Halliburton Company Oil well spacer fluids
US4650593A (en) 1977-09-19 1987-03-17 Nl Industries, Inc. Water-based drilling fluids having enhanced fluid loss control
CA1167403A (en) 1979-07-10 1984-05-15 Unilever Limited Microbial heteropolysaccharide
US4311607A (en) 1980-03-10 1982-01-19 Colgate Palmolive Company Method for manufacture of non-gelling, stable zeolite - inorganic salt crutcher slurries
US4368134A (en) 1980-03-10 1983-01-11 Colgate Palmolive Company Method for retarding gelation of bicarbonate-carbonate-zeolite-silicate crutcher slurries
US4372876A (en) 1980-05-02 1983-02-08 Uop Inc. Zeolite molecular sieve adsorbent for an aqueous system
US4363736A (en) * 1980-06-13 1982-12-14 W. R. Grace & Co. Fluid loss control system
US4474667A (en) * 1981-02-27 1984-10-02 W. R. Grace & Co. Fluid loss control system
DE3132928C1 (en) 1981-08-20 1983-01-13 Degussa Ag, 6000 Frankfurt Process for accelerating the setting of hydraulic cement mixtures
FR2516526B1 (en) 1981-11-16 1987-05-22 Rhone Poulenc Spec Chim WATER-SOLUBLE GUM COMPOSITIONS, THEIR PREPARATION AND THEIR USE
US4444668A (en) 1981-12-31 1984-04-24 Halliburton Company Well completion fluid compositions
US4536297A (en) 1982-01-28 1985-08-20 Halliburton Company Well drilling and completion fluid composition
US4530402A (en) 1983-08-30 1985-07-23 Standard Oil Company Low density spacer fluid
US4482379A (en) 1983-10-03 1984-11-13 Hughes Tool Company Cold set cement composition and method
US4515216A (en) 1983-10-11 1985-05-07 Halliburton Company Method of using thixotropic cements for combating lost circulation problems
DE3344291A1 (en) 1983-12-07 1985-06-13 Skw Trostberg Ag, 8223 Trostberg DISPERSING AGENT FOR SALTY SYSTEMS
US4515635A (en) 1984-03-23 1985-05-07 Halliburton Company Hydrolytically stable polymers for use in oil field cementing methods and compositions
US4555269A (en) 1984-03-23 1985-11-26 Halliburton Company Hydrolytically stable polymers for use in oil field cementing methods and compositions
HU195457B (en) 1984-04-02 1988-05-30 Vizepitoeipari Troeszt Process for removing suspended materials, biogene nutrients and soluted metal-compounds from waters containing organic and inorganic impurities
US4552591A (en) 1984-05-15 1985-11-12 Petrolite Corporation Oil field biocide composition
US4557763A (en) 1984-05-30 1985-12-10 Halliburton Company Dispersant and fluid loss additives for oil field cements
US4632186A (en) 1985-12-27 1986-12-30 Hughes Tool Company Well cementing method using an AM/AMPS fluid loss additive blend
US4717488A (en) 1986-04-23 1988-01-05 Merck Co., Inc. Spacer fluid
US4703801A (en) 1986-05-13 1987-11-03 Halliburton Company Method of reducing fluid loss in cement compositions which may contain substantial salt concentrations
US4676317A (en) 1986-05-13 1987-06-30 Halliburton Company Method of reducing fluid loss in cement compositions which may contain substantial salt concentrations
AU608038B2 (en) 1987-09-04 1991-03-21 Sumitomo Chemical Company, Limited A copper zeolite fungicide composition
US4784693A (en) 1987-10-30 1988-11-15 Aqualon Company Cementing composition and aqueous hydraulic cementing solution comprising water-soluble, nonionic hydrophobically modified hydroxyethyl cellulose
US5252554A (en) 1988-12-19 1993-10-12 Henkel Kommanditgesellschaft Auf Aktien Drilling fluids and muds containing selected ester oils
US5807810A (en) 1989-08-24 1998-09-15 Albright & Wilson Limited Functional fluids and liquid cleaning compositions and suspending media
US5123487A (en) 1991-01-08 1992-06-23 Halliburton Services Repairing leaks in casings
US5125455A (en) 1991-01-08 1992-06-30 Halliburton Services Primary cementing
US5121795A (en) 1991-01-08 1992-06-16 Halliburton Company Squeeze cementing
US5127473A (en) 1991-01-08 1992-07-07 Halliburton Services Repair of microannuli and cement sheath
US5238064A (en) 1991-01-08 1993-08-24 Halliburton Company Squeeze cementing
AU1762692A (en) 1991-03-29 1992-11-02 Raymond S. Chase Silica-containing cement and concrete composition
JPH07115897B2 (en) 1991-08-05 1995-12-13 財団法人鉄道総合技術研究所 Cement admixture for suppressing deterioration of concrete
US5151131A (en) 1991-08-26 1992-09-29 Halliburton Company Cement fluid loss control additives and methods
US5340860A (en) 1992-10-30 1994-08-23 Halliburton Company Low fluid loss cement compositions, fluid loss reducing additives and methods
US5346012A (en) 1993-02-01 1994-09-13 Halliburton Company Fine particle size cement compositions and methods
US5529624A (en) 1994-04-12 1996-06-25 Riegler; Norbert Insulation material
US5566760A (en) 1994-09-02 1996-10-22 Halliburton Company Method of using a foamed fracturing fluid
US5759964A (en) 1994-09-28 1998-06-02 Halliburton Energy Services, Inc. High viscosity well treating fluids, additives and methods
US5626665A (en) 1994-11-04 1997-05-06 Ash Grove Cement Company Cementitious systems and novel methods of making the same
US5494513A (en) 1995-07-07 1996-02-27 National Research Council Of Canada Zeolite-based lightweight concrete products
US5716910A (en) 1995-09-08 1998-02-10 Halliburton Company Foamable drilling fluid and methods of use in well drilling operations
US5588489A (en) 1995-10-31 1996-12-31 Halliburton Company Lightweight well cement compositions and methods
US5711383A (en) 1996-04-19 1998-01-27 Halliburton Company Cementitious well drilling fluids and methods
MX9602271A (en) 1996-06-10 1998-04-30 Cemex S A De C V High resistance hydraulic cement with accelerated development.
US5866517A (en) 1996-06-19 1999-02-02 Atlantic Richfield Company Method and spacer fluid composition for displacing drilling fluid from a wellbore
US5789352A (en) 1996-06-19 1998-08-04 Halliburton Company Well completion spacer fluids and methods
US5680900A (en) 1996-07-23 1997-10-28 Halliburton Energy Services Inc. Method for enhancing fluid loss control in subterranean formation
US6258757B1 (en) 1997-03-14 2001-07-10 Halliburton Energy Services, Inc. Water based compositions for sealing subterranean zones and methods
US6060434A (en) 1997-03-14 2000-05-09 Halliburton Energy Services, Inc. Oil based compositions for sealing subterranean zones and methods
US5913364A (en) 1997-03-14 1999-06-22 Halliburton Energy Services, Inc. Methods of sealing subterranean zones
GB9708831D0 (en) 1997-04-30 1997-06-25 Unilever Plc Suspensions with high storage stability, comprising an aqueous silicate solution and filler material
US6070664A (en) 1998-02-12 2000-06-06 Halliburton Energy Services Well treating fluids and methods
AU9585698A (en) 1997-09-30 1999-04-23 Bj Services Company Multi-functional additive for use in well cementing
FR2771444B1 (en) 1997-11-26 2000-04-14 Schlumberger Cie Dowell IMPROVEMENT OF THE PLACEMENT OF CEMENT GROUT IN WELLS IN THE PRESENCE OF GEOLOGICAL ZONES CONTAINING SWELLING CLAYS OR SLUDGE CONTAINING CLAYS
US6145591A (en) 1997-12-12 2000-11-14 Bj Services Company Method and compositions for use in cementing
US6230804B1 (en) 1997-12-19 2001-05-15 Bj Services Company Stress resistant cement compositions and methods for using same
US6171386B1 (en) 1998-01-22 2001-01-09 Benchmark Research& Technology Inc. Cementing compositions, a method of making therefor, and a method for cementing wells
US6409819B1 (en) 1998-06-30 2002-06-25 International Mineral Technology Ag Alkali activated supersulphated binder
US6245142B1 (en) * 1999-01-12 2001-06-12 Halliburton Energy Services, Inc. Flow properties of dry cementitious materials
US6170575B1 (en) 1999-01-12 2001-01-09 Halliburton Energy Services, Inc. Cementing methods using dry cementitious materials having improved flow properties
US6379456B1 (en) 1999-01-12 2002-04-30 Halliburton Energy Services, Inc. Flow properties of dry cementitious and non-cementitious materials
US6063738A (en) 1999-04-19 2000-05-16 Halliburton Energy Services, Inc. Foamed well cement slurries, additives and methods
US6209646B1 (en) 1999-04-21 2001-04-03 Halliburton Energy Services, Inc. Controlling the release of chemical additives in well treating fluids
US6283213B1 (en) 1999-08-12 2001-09-04 Atlantic Richfield Company Tandem spacer fluid system and method for positioning a cement slurry in a wellbore annulus
CA2316059A1 (en) * 1999-08-24 2001-02-24 Virgilio C. Go Boncan Methods and compositions for use in cementing in cold environments
US6182758B1 (en) 1999-08-30 2001-02-06 Halliburton Energy Services, Inc. Dispersant and fluid loss control additives for well cements, well cement compositions and methods
CA2318703A1 (en) 1999-09-16 2001-03-16 Bj Services Company Compositions and methods for cementing using elastic particles
US6213213B1 (en) 1999-10-08 2001-04-10 Halliburton Energy Services, Inc. Methods and viscosified compositions for treating wells
US6475275B1 (en) 1999-10-21 2002-11-05 Isolatek International Cement composition
US6138759A (en) 1999-12-16 2000-10-31 Halliburton Energy Services, Inc. Settable spotting fluid compositions and methods
US6315042B1 (en) 2000-07-26 2001-11-13 Halliburton Energy Services, Inc. Oil-based settable spotting fluid
US6457524B1 (en) 2000-09-15 2002-10-01 Halliburton Energy Services, Inc. Well cementing compositions and methods
US6508308B1 (en) * 2000-09-26 2003-01-21 Baker Hughes Incorporated Progressive production methods and system
US6405801B1 (en) 2000-12-08 2002-06-18 Halliburton Energy Services, Inc. Environmentally acceptable well cement fluid loss control additives, compositions and methods
US6767868B2 (en) * 2001-02-22 2004-07-27 Bj Services Company Breaker system for fracturing fluids used in fracturing oil bearing formations
US6488091B1 (en) 2001-06-11 2002-12-03 Halliburton Energy Services, Inc. Subterranean formation treating fluid concentrates, treating fluids and methods
US6616753B2 (en) * 2001-12-11 2003-09-09 Halliburton Energy Services, Inc. Methods and compositions for sealing subterranean zones
US6887828B2 (en) * 2001-12-21 2005-05-03 A. John Allen Phillipsitic zeolite soil amendments
US6555505B1 (en) * 2002-03-08 2003-04-29 Halliburton Energy Services, Inc. Foamed acidizing fluids, additives and methods of acidizing subterranean zones
US6722434B2 (en) * 2002-05-31 2004-04-20 Halliburton Energy Services, Inc. Methods of generating gas in well treating fluids
US6565647B1 (en) * 2002-06-13 2003-05-20 Shieldcrete Ltd. Cementitious shotcrete composition
US6702044B2 (en) * 2002-06-13 2004-03-09 Halliburton Energy Services, Inc. Methods of consolidating formations or forming chemical casing or both while drilling
US7544640B2 (en) * 2002-12-10 2009-06-09 Halliburton Energy Services, Inc. Zeolite-containing treating fluid
US6964302B2 (en) * 2002-12-10 2005-11-15 Halliburton Energy Services, Inc. Zeolite-containing cement composition
US7147067B2 (en) * 2002-12-10 2006-12-12 Halliburton Energy Services, Inc. Zeolite-containing drilling fluids
US7048053B2 (en) * 2002-12-10 2006-05-23 Halliburton Energy Services, Inc. Zeolite compositions having enhanced compressive strength
US6889767B2 (en) * 2003-02-28 2005-05-10 Halliburton E{umlaut over (n)}ergy Services, Inc. Cementing compositions and methods of cementing in a subterranean formation using an additive for preventing the segregation of lightweight beads.
US20050034864A1 (en) * 2003-06-27 2005-02-17 Caveny William J. Cement compositions with improved fluid loss characteristics and methods of cementing in surface and subterranean applications
US7137448B2 (en) * 2003-12-22 2006-11-21 Bj Services Company Method of cementing a well using composition containing zeolite
US6840319B1 (en) * 2004-01-21 2005-01-11 Halliburton Energy Services, Inc. Methods, compositions and biodegradable fluid loss control additives for cementing subterranean zones

Patent Citations (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4888120A (en) * 1986-09-18 1989-12-19 Henkel Kommanditgesellschaft Auf Aktien Water-based drilling and well-servicing fluids with swellable, synthetic layer silicates
JPH073254A (en) * 1991-01-28 1995-01-06 Terunaito:Kk Composition for drilling fluid
EP1428805A1 (en) * 2002-12-10 2004-06-16 Halliburton Energy Services, Inc. Cement composition

Non-Patent Citations (1)

* Cited by examiner, † Cited by third party
Title
PATENT ABSTRACTS OF JAPAN vol. 1995, no. 04 31 May 1995 (1995-05-31) *

Cited By (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2006010879A1 (en) * 2004-07-28 2006-02-02 Halliburton Energy Services, Inc. Cement-free zeolite and fly ash settable fluids and methods therefor
US7219733B2 (en) 2004-09-29 2007-05-22 Halliburton Energy Services, Inc. Zeolite compositions for lowering maximum cementing temperature
JP2008530328A (en) * 2005-02-17 2008-08-07 ビーエーエスエフ ソシエタス・ヨーロピア Formulation of polycondensate

Also Published As

Publication number Publication date
US20040188091A1 (en) 2004-09-30
CA2549515C (en) 2009-10-27
CA2549515A1 (en) 2005-06-30
US7150321B2 (en) 2006-12-19

Similar Documents

Publication Publication Date Title
CA2549515C (en) Zeolite-containing settable spotting fluids
US7048053B2 (en) Zeolite compositions having enhanced compressive strength
CA2575212C (en) Cement-free zeolite and fly ash settable fluids and methods therefor
CA2549128C (en) Zeolite-containing remedial compositions
US7147067B2 (en) Zeolite-containing drilling fluids
US5711383A (en) Cementitious well drilling fluids and methods
US5464060A (en) Universal fluids for drilling and cementing wells
US7326291B2 (en) Cementitious compositions containing interground cement clinker and zeolite
US7448450B2 (en) Drilling and cementing with fluids containing zeolite
US7350576B2 (en) Methods of sealing subterranean formations using rapid setting plugging compositions
US7544641B2 (en) Rapid setting plugging compositions for sealing subterranean formations
CA2618150C (en) Rapid setting plugging compositions and methods for sealing subterranean formations

Legal Events

Date Code Title Description
AK Designated states

Kind code of ref document: A1

Designated state(s): AE AG AL AM AT AU AZ BA BB BG BR BW BY BZ CA CH CN CO CR CU CZ DE DK DM DZ EC EE EG ES FI GB GD GE GH GM HR HU ID IL IN IS JP KE KG KP KR KZ LC LK LR LS LT LU LV MA MD MG MK MN MW MX MZ NA NI NO NZ OM PG PH PL PT RO RU SC SD SE SG SK SL SY TJ TM TN TR TT TZ UA UG US UZ VC VN YU ZA ZM ZW

AL Designated countries for regional patents

Kind code of ref document: A1

Designated state(s): BW GH GM KE LS MW MZ NA SD SL SZ TZ UG ZM ZW AM AZ BY KG KZ MD RU TJ TM AT BE BG CH CY CZ DE DK EE ES FI FR GB GR HU IE IS IT LU MC NL PL PT RO SE SI SK TR BF BJ CF CG CI CM GA GN GQ GW ML MR NE SN TD TG

121 Ep: the epo has been informed by wipo that ep was designated in this application
WWE Wipo information: entry into national phase

Ref document number: 2549515

Country of ref document: CA

NENP Non-entry into the national phase

Ref country code: DE

WWW Wipo information: withdrawn in national office

Country of ref document: DE

122 Ep: pct application non-entry in european phase