Wellbore sealant using nanoparticles
A wellbore is internally sealed using nanoparticles. Permeability properties are determined for a particular formation, along with its pore throat size distribution. A wellbore internal sealant (nanoparticle treatment fluid) is designed based on the determined permeability properties and pore throat size distribution. The nanoparticle treatment fluid is introduced into the formation. Pore throats within the formation are plugged by nanoparticles in the nanoparticle treatment fluid. Internal sealing reduces leak-off from filtercake damage, and also eliminates build-up of surface filtercake. Sealing the pore-structure of a particular wellbore zone alleviates the need for additional lost circulation material, resulting in a very thin filtercake and significantly reducing the chance of differential sticking. Oil-based muds can be replaced with water-based equivalents. The nanoparticle treatment fluid results in a permanent reduction in formation permeability, and therefore is particularly suitable for wells that will be stimulated using perforations, matrix acidizing, or fracturing techniques.
1. A method, comprising:
determining permeability properties and pore throat size distribution of a formation penetrated by a wellbore wherein determining permeability properties comprises analyzing a core sample or formation drilling cuttings and wherein the analyzing comprises using one or more techniques selected from the group consisting of: mercury injection capillary pressure (MICP), nuclear magnetic resonance (NMR), and liquid permeability laboratory measurements;
designing a nanoparticle treatment fluid based on the determined permeability properties and pore throat size distribution;
introducing the nanoparticle treatment fluid into the formation; and
plugging pore throats in the formation with nanoparticles in the nanoparticle treatment fluid, thereby producing an internally sealed formation.
2. The method of claim 1 , further comprising leaving wellbore sections surrounded by the internally sealed formation uncased.
3. The method of claim 1 , wherein the nanoparticle treatment fluid is water-based.
4. The method of claim 1 , further comprising:
producing a thin external filtercake on the wellbore wall surface adjacent to the internally sealed formation.
5. The method of claim 1 , wherein designing a nanoparticle treatment fluid comprises estimating an optimal particle size distribution or collection of monodisperse distributions for loading the nanoparticle treatment fluid.
6. The method of claim 1 , wherein designing a nanoparticle treatment fluid comprises correlating logging-while-drilling data with the determined permeability properties.
7. The method of claim 1 , wherein designing a nanoparticle treatment fluid comprises analyzing a baseline wellbore internal sealant mixture.
8. The method of claim 7 , wherein the analyzing is done using a reservoir core or a reservoir analogue.
9. The method of claim 7 , further comprising:
modifying the particle size distribution of the baseline wellbore internal sealant based on the results of the analysis.
10. The method of claim 1 , wherein designing a nanoparticle treatment fluid comprises performing stimulation testing to select a stimulation technique.
11. The method of claim 10 , wherein the stimulation technique is selected from a group consisting of: fracture stimulation, matrix stimulation, and jetting/perforating past a damaged region in the wellbore.
12. The method of claim 1 , wherein the nanoparticle treatment fluid comprises a nanoparticle composition selected from a group consisting of: compounds of silica, carbon, titanium dioxide, cerium oxide, and nanocrystalline cellulose.
13. The method of claim 1 , further comprising:
enhancing casing spacing in the wellbore.
14. The method of claim 1 , further comprising conditioning the wellbore to avoid differential sticking.
15. A method, comprising:
determining permeability properties and pore throat size distribution of a formation penetrated by a wellbore wherein determining permeability properties comprises analyzing a core sample or formation drilling cuttings and wherein the analyzing comprises using one or more techniques selected from the group consisting of: mercury injection capillary pressure (MICP), nuclear magnetic resonance (NMR), and liquid permeability laboratory measurements;
designing a nanoparticle treatment fluid based on the determined permeability properties and pore throat size distribution;
sealing a subsurface formation penetrated by a wellbore by introducing the nanoparticle treatment material into the formation; and
holding a volume of nanoparticle treatment material in reserve within a drillstring or bottomhole assembly, and, upon command, releasing the nanoparticle treatment material, thereby effecting the seal in real-time.
16. The method of claim 15 , further comprising:
selecting a stimulation zone.
17. The method of claim 15 , further comprising:
enhancing a wellbore/casing bond in a cementing operation.
18. The method of claim 15 , further comprising:
functionalizing the nanoparticle treatment material to allow for subsequent detection and/or location.
19. The method of claim 15 , wherein the introducing a nanoparticle treatment material into the formation is done continuously, in quasi-real-time, or in true real-time.