Method for tracking a treatment fluid in a subterranean formation

Abstract

A method of tracking a treatment fluid in a subterranean formation penetrated by a wellbore provides for injecting the treatment fluid with the plurality of tracer agents into the well and the formation. Each tracer agent is an object of submicron scale. The location and distribution of the treatment fluid is determined by detecting changes in the physical properties of the formation caused by the arrival of the treatment fluid comprising a plurality of tracer agents.

1 . A method of tracking a treatment fluid in a subterranean formation penetrated by a wellbore comprising the steps of:
 providing a treatment fluid comprising a plurality of tracer agents, wherein each tracer agent is an object of submicron scale,   injecting the treatment fluid with the plurality of tracer agents into the well and the formation, and   determining the location and distribution of the treatment fluid by detecting changes in the physical properties of the formation caused by the arrival of the treatment fluid comprising a plurality of tracer agents.   
     
     
         2 . The method of  claim 1  wherein the treatment fluid is selected from the group consisting of fracturing fluids, drilling fluids, acidizing fluids, injection fluids, brines and completion fluids, fluids for EOR/IOR including reservoir flooding fluids. 
     
     
         3 . The method of  claim 1  wherein the plurality of tracer agents are low or insoluble gas bubbles having a diameter not more than 500 nm, the treatment fluid is water- or hydrocarbon-based solution and the treatment fluid with the plurality of tracer agents is a highly dispersed gas-liquid mixture. 
     
     
         4 . The method of  claim 3  wherein the gas is selected from the group consisting of methane, higher molecular weight hydrocarbon gas, nitrogen or other insoluble inorganic gas or mixtures of thereof. 
     
     
         5 . The method of  claim 3  wherein the water-based solution additionally comprises electrolytes of ferrous ions, manganese ions, calcium ions, or any other mineral ion such that the electrical conductivity in the solution is not less than 300 μ8 Λ;m. 
     
     
         6 . The method of  claim 1  wherein the plurality of tracer agents are high viscous liquid droplets having a diameter not more than 1000 nm, the treatment fluid is water- or hydrocarbon-based solution and the treatment fluid with the plurality of tracer agents is an emulsion. 
     
     
         7 . The method of  claim 6  wherein the high viscous liquid is crude oil or toluene. 
     
     
         8 . The method of  claim 1  wherein the plurality of tracer agents are solid particles and the treatment fluid with the plurality of tracer agents is a stabilized solution in aqueous fluids, solvent based fluids such as alcohols or hydrocarbon based fluids. 
     
     
         9 . The method of  claim 8  wherein the solid particles are selected from the group consisting of silica, synthesized copper, magnetite (Fe304), ferri/ferrous chlorides, barium iron oxide (BaFe12019), zinc oxide, aluminium oxide, magnesium oxide, zirconium oxide, titanium oxide, cobalt (II) and nickel (II) oxide, barium sulfate (BaS04), pyrolectric and piezoelectric crystals etc. 
     
     
         10 . The method of  claim 1  wherein the treatment fluid comprising a plurality of tracer agents is provided by mixing the treatment fluid with the plurality of tracer agents by means of a generator placed in the wellbore. 
     
     
         11 . The method of  claim 1  wherein the treatment fluid comprising a plurality of tracer agents is provided by mixing the treatment fluid with the plurality of tracer agents by means of the surface located equipment. 
     
     
         12 . The method of  claim 1  wherein the treatment fluid comprising a plurality of tracer agents is injected continuously during the treatment duration. 
     
     
         13 . The method of  claim 1  wherein the treatment fluid comprising a plurality of tracer agents is injected periodically during the treatment duration. 
     
     
         14 . The method of  claim 1  wherein the treatment fluid comprising a plurality of tracer agents is injected at any stage of the treatment. 
     
     
         15 . The method of  claim 1  wherein the injection of the treatment fluid is accompanied by physical treatment performed before, during or after the injection process. 
     
     
         16 . The method of  claim 15  wherein the physical treatment is vibration, or heating, or acoustic treatments. 
     
     
         17 . The method of  claim 1  wherein the treatment fluid additionally comprises one or more additives selected from a group comprising gelling agents, foaming agents, friction reducers, surfactants. 
     
     
         18 . The method of  claim 1  wherein physical properties of the formation are acoustic impedance and/or electric conductivity and/or magnetic permittivity, nuclear magnetic resonance (NMR) response, thermal propagation and hydrodynamic flow capabilities 
     
     
         19 . The method of  claim 1  wherein detecting of physical properties of the formation is made by seismic, acoustic, electrical, electrokinetical, NMR, thermal, neutron or gamma-ray means. 
     
     
         20 . The method of  claim 19  wherein detecting of physical properties of the formation is made by seismic, acoustic, electrical, electrokinetical, NMR, thermal, neutron or gamma-ray means located on the surface. 
     
     
         21 . The method of  claim 19  wherein detecting of physical properties of the formation is made by seismic, acoustic, electrical, electrokinetical, NMR, thermal, neutron or gamma-ray means located in the wellbore. 
     
     
         22 . The method of  claim 1  wherein the treatment fluid with the plurality of tracer agents is flowed back from the subterranean formation and analyzed for changes in the tracer agents concentration, size, type and distribution function between the injected and produced treatment fluid. 
     
     
         23 . The method of  claim 22  wherein analyzing changes in the tracer agents concentration, size and type distribution function between the injected and produced treatment fluids is performed while flowing in the formation by the acoustics, electric, thermal, neutron or gamma-ray logging. 
     
     
         24 . The method of  claim 22  wherein analyzing changes in the tracer agents concentration, size and type distribution function between the injected and produced treatment fluids is performed by comparing samples of the injection and produced fluids.