Time-delay Fluids for Wellbore Cleanup

Abstract

A method for delaying the removal of a majority of an oil-based mud (OBM) filter cake from a hydrocarbon reservoir wellbore that utilizes a multiple phase composition is described. The use of the multiple phase composition allows for a microemulsion, a miniemulsion, or a nanoemulsion to form in situ downhole at a controllable time. The method includes pumping the multiple phase composition comprising an additive into the wellbore. The multiple phase composition may be broken thereby releasing the additive. The broken multiple phase composition and the additive may contact the OBM filter cake particles to form an in situ emulsion selected from the group consisting of a nanoemulsion, a miniemulsion, a microemulsion, a multiple emulsion, a water-continuous emulsion and mixtures thereof. The in situ emulsion may incorporate more of the external oil from the OBM filter cake in order to more easily remove the OBM filter cake.

What is claimed is:  
     
         1 . A method for removing a majority of oily material in the near-wellbore area including oil-based mud (OBM) filter cake from a hydrocarbon reservoir wellbore comprising:
 delivering a multiple phase composition comprising an additive into the wellbore;   breaking the multiple phase composition thereby releasing the additive;   contacting the OBM filter cake particles with the broken multiple phase composition and the released additive to form an in situ emulsion downhole, wherein the in situ emulsion is selected from the group consisting of a nanoemulsion, a miniemulsion, a microemulsion, a water-continuous emulsion, and mixtures thereof; and   incorporating a majority of the external oil from the OBM filter cake into the in situ emulsion.   
     
     
         2 . The method of  claim 1 , wherein the multiple phase composition has at least an internal phase and a second phase; and wherein the additive is dispersed within the internal phase, the second phase, and combinations thereof. 
     
     
         3 . The method of  claim 2 , wherein the proportion of the internal phase in the multiple phase composition ranges from about 1 vol. % to about 90 vol. %. 
     
     
         4 . The method of  claim 2 , wherein the internal phase comprises vesicles ranging in size from about 0.01 microns to about 1000 microns. 
     
     
         5 . The method of  claim 1 , wherein the additive is selected from the group consisting of structural stabilizers, surfactants, viscosifiers, chelating agents, filtration control additives, suspending agents, dispersants, wetting agents, solvents, co-solvents, co-surfactants, acids, and mixtures thereof. 
     
     
         6 . The method of  claim 5 , wherein the surfactant is selected from the group consisting of non-ionic surfactants, anionic surfactant, cationic surfactants, amphoteric, zwitterionic surfactants, extended surfactants, and combinations thereof. 
     
     
         7 . The method of  claim 5 , wherein the proportion of the structural stabilizer based on the total of the internal phase and the second phase, prior to injection into the third phase for transport, ranges from about 0.1 vol. % to about 90 vol. %. 
     
     
         8 . The method of  claim 1  further comprising drilling a wellbore in a hydrocarbon reservoir with an OBM prior to delivering the multiple phase composition into the wellbore. 
     
     
         9 . The method of  claim 1  further comprising forming an OBM filter cake over at least part of the wellbore prior to breaking the multiple phase composition for release of an additive. 
     
     
         10 . The method of  claim 1  where incorporating a majority of the oil from the OBM filter cake into the in situ emulsion creates a characteristic selected from the group consisting of where formation skin damage to the wellbore is reduced, where subsequent hydrocarbon recovery is increased, where subsequent water injection rate into the reservoir is increased, and combinations thereof as compared with an otherwise identical method absent the in situ emulsion formed downhole. 
     
     
         11 . The method of  claim 1 , wherein the in situ emulsion comprises a non-polar liquid selected from the group consisting of synthetic base and mineral oils, ester fluids, paraffins, isomerized olefins, and mixtures thereof. 
     
     
         12 . The method of  claim 1 , wherein a chelating agent has been added to the multiple phase composition according to a procedure selected from the group consisting of:
 adding the chelating agent to a phase of the multiple phase composition;   adding the chelating agent directly to the OBM after the multiple phase composition has been broken;   adding the chelating agent to the broken multiple phase composition; and   a combination thereof;   
       where the chelating agent improves the incorporating of the external oil from the OBM filter cake into the in situ emulsion as compared to an identical in situ emulsion absent the chelating agent. 
     
     
         13 . The method of  claim 12 , wherein the chelating agent comprises an acid selected from the group of inorganic acids consisting of hydrochloric acid, sulfuric acid, and organic acids consisting of acetic acid, formic acid and salts thereof, and mixtures thereof. 
     
     
         14 . The method of  claim 12 , wherein the chelating agent is a polyamino carboxylic acid selected from the group consisting of nitrilotriacetic acid (NTA), ethylenediamine tetraacetic acid (EDTA), trans-1,2-diaminocyclohexane-N,N,N′,N′,-tetraacetic acid monohydrate (CDTA), diethylenetriamine pentaacetic acid (DTPA), dioxaoctamethylene dinitrilo tetraacetic acid (DOCTA), hydroxy-ethylethylenediamine triacetic acid (HEDTA), triethylenetetramine hexaacetic acid (TTNA), trans-1,2diaminocyclohexane tetraacetic acid (DCTA), and salts thereof, and mixtures thereof. 
     
     
         15 . The method of  claim 12 , wherein the concentration of the chelating agent in the multiple phase composition ranges from about 1 to about 30 vol %. 
     
     
         16 . The method of  claim 1 , wherein the multiple phase composition further comprises a water-soluble filtration control additive selected from the group consisting of modified starch, polymers, and mixtures thereof. 
     
     
         17 . The method of  claim 16 , wherein the proportion of the water-soluble filtration control additive in the multiple phase composition ranges from about 0.1 lb/bbl to about 10 lb/bbl. 
     
     
         18 . The method of  claim 1 , wherein the filter cake particles are selected from the group consisting of calcium carbonate, hematite, ilmenite, manganese tetroxide, manganous oxide, iron carbonate, magnesium oxide, barium sulfate, and mixtures thereof. 
     
     
         19 . A method for removing a majority of an oil-based mud (OBM) filter cake from a hydrocarbon reservoir wellbore comprising:
 breaking a multiple phase composition after delivery of the multiple phase composition into a wellbore thereby releasing the additive, wherein the multiple phase composition comprises an internal phase having at least one component thereby releasing the at least one internal phase component, wherein the at least one internal phase component is selected from the group consisting of structural stabilizers, surfactants, viscosifiers, chelating agents, filtration control additives, suspending agents, dispersants, wetting agents, and mixtures thereof;   contacting OBM filter cake particles with the broken multiple phase composition and the released internal phase component to form an in situ emulsion downhole, wherein the in situ emulsion is selected from the group consisting of a nanoemulsion, a miniemulsion, a microemulsion, and mixtures thereof; and   incorporating a majority of the external oil from the OBM filter cake into the in situ emulsion.   
     
     
         20 . A method for removing a majority of an oil-based mud (OBM) filter cake from a hydrocarbon reservoir wellbore comprising:
 delivering a multiple phase composition comprising an internal phase having at least one component into the wellbore;   breaking the multiple phase composition thereby releasing the at least one internal phase component, wherein the at least one internal phase component is selected from the group consisting of structural stabilizers, surfactants, viscosifiers, chelating agents, filtration control additives, suspending agents, dispersants, wetting agents, and mixtures thereof;   contacting OBM filter cake particles with the broken multiple phase composition and the released internal phase component to form an in situ emulsion downhole, wherein the in situ emulsion is selected from the group consisting of a nanoemulsion, a miniemulsion, a microemulsion, and mixtures thereof; and   incorporating a majority of the external oil from the OBM filter cake into the in situ emulsion.