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ZEOLITE COMPOSITIONS HAVING
ENHANCED COMPRESSIVE STRENGTH
CROSS-REFERENCE TO RELATED
This application is a divisional of application Ser. No. 10/822,459 filed Apr. 12, 2004, now U.S. Pat. No. 7,048, 053, the entire disclosure of which is incorporated by reference herein, which is a continuation-in-part of application Ser. No. 10/738,199 filed Dec. 17, 2003, now U.S. Pat. No. 7,150,321, the entire disclosure of which is incorporated by reference herein, which is a continuation-in-part of prior application Ser. No. 10/727,370 filed Dec. 4, 2003, now U.S. 15 Pat. No. 7,140,439, the entire disclosure of which is incorporated herein by reference, which is a continuation-in-part of prior application Ser. No. 10/686,098 filed Oct. 15, 2003, now U.S. Pat. No. 6,964,302, the entire disclosure of which is incorporated herein by reference, which is a continuation- 20 in-part of prior application Ser. No. 10/623,443 filed Jul. 18, 2003, the entire disclosure of which is incorporated herein by reference, and which is a continuation-in-part of prior application Ser. No. 10/315,415, filed Dec. 10, 2002, now U.S. Pat. No. 6,989,057, the entire disclosure of which is 25 incorporated herein by reference.
Zeolites are known to be pozzolanic materials and may be 30 stabilized with alkali or Portland cement in the presence of sufficient water. In most cases, it is possible to accelerate or retard the setting time by using conventional cement additives. However, it is the final strength of the composition that is of industrial concern. 35
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 Typically, after a wellbore has been drilled to total depth, the drill bit is withdrawn from the wellbore, and circulation of 40 the drilling fluid is stopped, thereby initiating a shutdown period.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 45 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 5Q 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. 55
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 60 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. 65
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 zeolite compositions having enhanced strength and desirable setting times. In particular, such compositions are useful as wellbore treating fluids in the form of settable spotting fluids in drilling operations.
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 shows compressive strength in pounds per square inch (psi) from ultrasonic cement analyzer data at 160° F. and 3000 psi for 11.5 pounds per gallon (ppg) slurries versus fraction of lime by weight of zeolite/lime composition. The circles mark data using the zeolite chabazite and the triangles mark data using the zeolite clinoptilolite.
FIG. 2 shows particle size histographs for chabazite and clinoptilolite as described in Example 3.
FIG. 3 shows compressive strength in pounds per square inch (psi) from ultrasonic cement analyzer data at 160° F. and 3000 psi for 11.5 ppg slurries versus amount of citric acid in percent by weight of zeolite. The ratio of zeolite and activator in the composition is 74:26.
FIG. 4 provides a compressive strength versus time plot for compositions lacking citric acid and compositions having 0.8% citric acid.
According to embodiments described herein, enhanced compressive strength zeolite compositions are provided having desirable setting times. The final strength or saturated 5 compressive strength of a zeolite composition, i.e., a compressive strength at which further setting time contributes a minimal amount to the compressive strength, is dependent upon the zeolite/activator ratio in the composition, carrier, fluid content, particle size, and reaction temperature and 10 time. Compositions of the present invention are useful as a replacement for hydraulic cement in addition to their use in wellbore treating fluids introduced into a subterranean zone penetrated by a wellbore, particularly wellbore treating fluids introduced as settable spotting fluids. According to the 15 present invention, compositions having such optimized parameters and including certain additives have enhanced compressive strengths for the set composition as compared to set compositions lacking such parameters and additives.
An embodiment of the present invention is a method of 20 increasing compressive strength of a zeolite/activator composition, the method comprising blending a zeolite having a mean particle size less than or equal to 100 microns, an activator at an amount greater than or equal to 5% and less than or equal to 50% by weight of zeolite/activator compo- 25 sition, an organic acid or salt thereof in an amount greater than or equal to 0.1% and less than or equal to 5.0% by weight of zeolite, and a carrier fluid to form a blended composition; and allowing the blended composition to set to form a set composition. The set composition has a greater 30 saturated compressive strength than that of a set zeolite/ activator composition lacking the organic acid or salt thereof.
Zeolites: Zeolites are porous alumino-silicate minerals that may be either a natural or manmade material. Manmade 35 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 40 zeolites. All zeolites are composed of a three-dimensional framework of Si04 and A104 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: 45
where M represents one or more cations such as Na, K, Mg, Ca, Sr, Li or Ba for natural zeolites and NH4, CH3NH3, (CH3)3NH, (CH3)4N, Ga, Ge and P for manmade zeolites; n 50 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 enhanced strength com- 55 positions 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 alumi- 60 num 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 alu- 65 minum 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 herein include chabazite and clinoptilolite.
Particle sizes of zeolites are measured on a Malvern Particle Size Analyzer, available from Malvern Instruments Ltd., of Worcestershire, UK, for example. For a given particle size, the Particle Size Analyzer identifies the volume percentage of particles in the sample that are beneath that particle size. The Particle Size Analyzer also provides a median particle size. Another parameter reported by the Particle Size Analyzer is the "Span," that describes the width of the distribution independent of the median particle size. As shown in Example 3, two zeolites, clinoptilolite and chabazite, have very similar mean size. However, clinoptilolite has a much higher span, meaning that that zeolite has more particles with larger sizes as compared to chabazite. A smaller sized particle provides a packed or reactive surface area that is greater than the packed or reactive surface area of larger sized particles. With a given zeolite-activator composition, compressive strength is inversely proportional to the span of the particle having comparable mean particle size. Better compressive strengths are obtained from smaller sized particles with a comparable or narrower distribution. According to certain embodiments described herein, the mean particle size for a zeolite is less than or equal to 100 microns. In further embodiments, the mean particle size for a zeolite of the present invention is less than or equal to 90 microns, 80 microns, 70 microns, 60 microns, 50 microns, 40 microns, 30 microns, 20 microns, or 10 microns. In a further embodiment, the mean particle size for a zeolite of the present invention is greater than 1.0 micron and less than or equal to 10 microns.
Activator: The activator is present in the composition in an amount greater than or equal to 5% and less than or equal to 50% by weight of zeolite/activator composition. In further embodiments, the activator is present in the composition in greater than or equal to 10%, 20%, 30%, or 40% by weight of the zeolite/activator composition. In one embodiment, the activator is present in the composition in an amount greater than or equal to 25% and less than or equal to 50% by weight of the zeolite/activator composition. In another embodiment, the activator is present in an amount of about 26% by weight of the zeolite/activator composition. The activator may be one or more of lime, calcium hydroxide, sodium silicate, sodium fluoride, sodium silicofluoride, magnesium silicofluoride, zinc silicofluoride, sodium carbonate, potassium carbonate, sodium hydroxide, potassium hydroxide, sodium sulfate, or hydrates thereof. In one embodiment, the activator is calcium hydroxide. Selection of the type and amount of activator depends on the type and make-up of the composition in which the activator is contained, and it is understood by those of ordinary skill in the art how to select a suitable type and amount of activator in light of the present disclosure.
Retarder: The term, "retarder," as used in this application means a composition having properties of slowing the setting time of a zeolite/activator composition. Suitable retarders include but are not limited to one or more of a lignosulfonate, an organic acid having an a-hydroxy group such as citric acid, tartaric acid or gluconic acid, and combinations of both lignosulfonate and organic acid having an a-hydroxy group.