Wellbore Servicing Fluid and Methods of Making and Using Same

Abstract

A method comprising (a) contacting a suspension composition, water, and optionally one or more additives to form a wellbore servicing fluid at a location proximate a wellsite; wherein the suspension composition comprises a particulate material, an organic carrier fluid, and a suspension viscosifier; and (b) placing the wellbore servicing fluid in a wellbore penetrating a subterranean formation. The wellsite comprises an offshore platform, a floating vessel, or combinations thereof; and wherein the wellbore is offshore. A suspension composition comprising a particulate material, an organic carrier fluid, and a suspension viscosifier; wherein the particulate material is substantially insoluble in the organic carrier fluid; wherein the particulate material comprises a water-interactive material and/or a water-insoluble material; and wherein the organic carrier fluid comprises a glycol and/or a glycol ether.

What is claimed is: 
     
         1 . A method comprising:
 (a) contacting a suspension composition, water, and optionally one or more additives to form a wellbore servicing fluid at a location proximate a wellsite; wherein the suspension composition comprises a particulate material, an organic carrier fluid, and a suspension viscosifier; and   (b) placing the wellbore servicing fluid in a wellbore penetrating a subterranean formation.   
     
     
         2 . The method of  claim 1 , wherein the wellsite comprises an offshore platform, a floating vessel, or combinations thereof; and wherein the wellbore is offshore. 
     
     
         3 . The method of  claim 1 , wherein the particulate material comprises a water-interactive material and/or a water-insoluble material; wherein the water-interactive material comprises an expansion agent, alkali metal oxides, alkaline earth metal oxides, magnesium oxide, lightly burned magnesium oxide, hard burned magnesium oxide, deadburned magnesium oxide, metal powders, aluminum powder, a gypsum blend; a viscosifying clay, bentonite, sepiolite, hectorite; a delayed viscosifier, crosslinked guar, crosslinked vinyl alcohols, crosslinked acrylamide polymers; a fluid loss agent, an acrylic-based polymer, a polyacrylate, an acrylamide-based polymer, a polyacrylamide, an acrylamide copolymer, an acrylic acid copolymer, a polymer of acrylamide-tertiary-butyl sulfonate (ATBS), an ATBS/acrylamide copolymer, 2-acrylamido-2-methylpropane sulfonic acid/acrylamide copolymers, 2-acrylamido-2-methylpropane sulfonic acid/N,N-dimethyl-acrylamide copolymers, vinylpyrrolidone/2-acrylamido-2-methylpropane sulfonic acid/acrylamide terpolymers, acrylamide/t-butyl acrylate/N-vinylpyrrolidone terpolymers, acrylamide/t-butyl acrylate/2-acrylamido-2-methylpropane sulfonic acid terpolymers, 2-acrylamido-2-methylpropane sulfonic acid/N-N-dimethylacrylamide/ acrylamide terpolymers, acrylamide/t-butyl acrylate/N-vinylpyrrolidone/2-acrylamido-2-methylpropane sulfonic acid tetrapolymers, acrylamide/t-butyl acrylate copolymers, poly(2-hydroxyethyl methacrylate), poly(2-hydroxypropyl methacrylate), derivatives thereof or combinations thereof and wherein the water-insoluble material comprises pozzolana cement; sand; a weighting agent, an iron oxide, hematite, a manganese oxide, hausmannite, a titanium-iron oxide, ilmenite; a fiber, a carbon fiber, an acrylonitrile fiber, a polypropylene fiber, a glass fiber, a rubber fiber; a rubber particle; a hollow glass sphere; a hollow pozzolanic sphere; a glass bubble; a glass ball; a ceramic ball; graphite; pozzolan; pumice; trass; clay; calcined clay; silica, fume silica, amorphous silica, micro-sized silica, nano-sized silica; or combinations thereof. 
     
     
         4 . The method of  claim 1 , wherein the particulate material is present in the suspension composition in an amount of from about 1 wt. % to about 80 wt. %, based on a total weight of the suspension composition. 
     
     
         5 . The method of  claim 1 , wherein the organic carrier fluid comprises a glycol and/or a glycol ether; wherein the glycol comprises monoethylene glycol, propylene glycol, butylene glycol, or combinations thereof and wherein the glycol ether comprises ethylene glycol monomethyl ether, ethylene glycol monoethyl ether, propylene glycol monomethyl ether, propylene glycol monoethyl ether, butylene glycol monomethyl ether, butylene glycol monoethyl ether, or combinations thereof. 
     
     
         6 . The method of  claim 1 , wherein the organic carrier fluid is present in the suspension composition in an amount of from about 20 wt. % to about 98.99 wt. %, based on a total weight of the suspension composition. 
     
     
         7 . The method of  claim 1 , wherein the suspension viscosifier comprises Guar gum, Xanthan gum, Welan gum, Diutan, hydroxyethyl cellulose (HEC), modified cellulose, diatomaceous earth, starch, modified and/or crosslinked starch, viscoelastic surfactants (VES), precipitated silica, derivatives thereof, or combinations thereof. 
     
     
         8 . The method of  claim 1 , wherein the suspension viscosifier is present in the suspension composition in an amount of from about 0.01 wt. % to about 20 wt. %, based on a total weight of the suspension composition. 
     
     
         9 . The method of  claim 1 , wherein the suspension composition is present in the wellbore servicing fluid in an amount of from about 0.1 wt. % to about 60 wt. %, based on a total weight of the wellbore servicing fluid. 
     
     
         10 . The method of  claim 1 , wherein the suspension composition has (A1) a density of from about 4 pounds per gallon (ppg) to about 25 ppg; (A2) a specific gravity of from about 0.5 to about 3; (A3) a pH in a range of from about 4 to about 12, when measured for 1 vol. % dilution of the suspension composition in water; (A4) a Brookfield viscosity of from about 50 cP to about 600 cP at 75° F. and 100 rpm; (A5) a flash point of equal to or greater than about 230° F.; (A6) a freezing point of from about 8° F. to about 24° F.; (A7) a boiling point of from about 210° F. to about 410° F.;
 or (A8) any combination of (A1)-(A7). 
 
     
     
         11 . The method of  claim 1 , wherein the wellbore servicing fluid is a cementitious fluid;
 wherein the contacting comprises (i) contacting the suspension composition with water to form a mixture, and (ii) contacting the mixture with a cement blend to form the wellbore servicing fluid;   wherein the one or more additives are optionally added to the mixture prior to contacting the mixture with the cement blend; and wherein the wellbore servicing fluid is allowed to set.   
     
     
         12 . The method of  claim 11  further comprising adding a weighting agent or a weight-reducing agent to the wellbore servicing fluid prior to placing the wellbore servicing fluid in the wellbore;
 wherein the weighting agent or the weight-reducing agent is added to the mixture prior to or concurrent with contacting the mixture with the cement blend. 
 
     
     
         13 . The method of  claim 11 , wherein the cement blend is present in the wellbore servicing fluid in an amount ranging from about 20 wt. % to about 90 wt. %, based on a total weight of the wellbore servicing fluid; and wherein the weighting agent or the weight-reducing agent is present in the wellbore servicing fluid in an amount of from about 1% by weight of blend (BWOB) to about 200% BWOB, based on a total weight of the cement blend. 
     
     
         14 . The method of  claim 11 , wherein the wellbore servicing fluid has (B1) a density of from about 9 pounds per gallon (ppg) to about 26 ppg; (132) a specific gravity of from about 1.1 to about 2.5; (B3) a mixability rating of from about 3 to about 5; (B4) a fluid loss of from about 10 ml per 30 minutes to about 250 ml per 30 minutes on 325 mesh screen at about 129° F. and about 1,000 psig differential pressure, when measured in accordance with a test standard API-RP-10B-2; (B5) a 10-second static gel strength of from about 1 to about 50, and a 10-minute static gel strength of from about 1 to about 300, at about 129° F., when measured in accordance with a test standard API-RP-10B-2; (B6) a thickening time of from about 3 hours to about 24 hours at about 129° F. and about 5000 psi when measured in accordance with a test standard API-RP-10B-2; (B7) a 50 psi UCA compressive strength of from about 1 hour to about 48 hours, a 500 psi UCA compressive strength of from about 2 hours to about 72 hours, and a 24 hr UCA compressive strength of from about 50 psig to about 10,000 psig, when measured at about 168° F. and about 5,000 psig in accordance with a test standard API-RP-10B-2; or (B8) any combination of (B1)-(B7). 
     
     
         15 . The method of  claim 11 , wherein a cement cured from the wellbore servicing fluid has (C1) a crush compressive strength of from about 500 psig to about 12,000 psig; (C2) a Young's Modulus of from about 0.3 Mpsig to about 3 Mpsig; (C3) a Brazilian Tensile Strength of from about 50 psig to about 1,600 psig; or (C4) any combination of (C1)-(C3). 
     
     
         16 . The method of  claim 1 , wherein the wellbore servicing fluid is a spacer fluid; and wherein the spacer fluid has a density in a range of from about 4 pounds per gallon (ppg) to about 25 ppg. 
     
     
         17 . A method comprising:
 (a) forming a suspension composition comprising a crosslinked guar, monoethylene glycol (MEG), and a suspension viscosifier;   (b) contacting the suspension composition with water to form a mixture at a location proximate a wellsite;   (c) contacting the mixture with a cement blend and optionally one or more additives, weighting agents or weight-reducing agents to form a wellbore servicing fluid;   (d) placing the wellbore servicing fluid in a wellbore penetrating a subterranean formation; and   (e) allowing the wellbore servicing fluid to set.   
     
     
         18 . The method of  claim 17 , wherein the method further comprises adding a gas to the wellbore servicing fluid, prior to placing the wellbore servicing fluid in a wellbore penetrating a subterranean formation; wherein a target density of the wellbore servicing fluid is from about 5 pounds per gallon (ppg) to about 16 ppg. 
     
     
         19 . The method of  claim 18 , wherein the gas is present in the wellbore servicing fluid placed in the wellbore in an amount of from about 10 vol. % to about 30 vol. %, based on a total volume of the wellbore servicing fluid placed in the wellbore. 
     
     
         20 . A method comprising:
 (a) contacting a crosslinked guar, monoethylene glycol (MEG), and a suspension viscosifier to form a suspension composition;   (b) conveying the suspension composition via a suspension flow line into water in a water flow line at a location proximate an offshore platform to form a diluted suspension;   (c) conveying one or more additives via one or more additive flow lines into the diluted suspension in a diluted suspension line to form a mixture;   (d) placing the mixture in a container;   (e) adding a cement blend and optionally a weighting agent or a weight-reducing agent into the container to form a slurry;   (f) blending the slurry to form a wellbore servicing fluid;   (g) placing the wellbore servicing fluid in an offshore wellbore penetrating a subterranean formation; and   (h) optionally allowing the wellbore servicing fluid to set.