Methods and compositions for mitigating fluid loss from well ballooning
A method of servicing a wellbore in a formation comprising circulating in the wellbore a wellbore servicing fluid wherein an equivalent circulating density of the wellbore servicing fluid is from about 1% to about 15% greater than a fracture pressure of the formation, and introducing to the wellbore a balloon-inhibiting tunable spacer (BITS) fluid wherein at least about 1 wt. % of the BITS fluid is retained by the formation.
1. A method of servicing a wellbore in a formation comprising:
circulating in the wellbore a wellbore servicing fluid wherein an equivalent circulating density of the wellbore servicing fluid is from about 1% to about 15% greater than a fracture pressure of the formation;
introducing to the wellbore a balloon-inhibiting tunable spacer (BITS) fluid, wherein at least about 1 wt. % of the BITS fluid is retained by the formation and
wherein a reduction in well ballooning is achieved as indicated by (i) a well pressure that is about zero; (ii) a return flow rate of about zero; (iii) a downhole temperature at a depth of a pervious zone remains about constant or (iv) any combination thereof.
2. The method of claim 1 further comprising determining a regain permeability of the formation.
3. The method of claim 2 wherein the regain permeability is from about 50% to about 100%.
4. The method of claim 1 wherein the equivalent circulating density of the wellbore servicing fluid ranges from about 8.5 lb/gal to about 20 lb/gal.
5. The method of claim 1 wherein the BITS fluid comprises a particulate material, a multifunctional polymer, and a viscosifier.
6. The method of claim 5 wherein the particulate material has a particle size distribution of from about 0.5 micron to about 5 mm.
7. The method of claim 5 wherein the particulate material comprises inorganic particles, carbonate-containing particles, polymeric materials, elastomeric materials or any combination thereof.
8. The method of claim 5 wherein the particulate material is selected from the group consisting of silica, graded sand, Ottawa sands, Brady sands, Colorado sands; gravels; synthetic organic particles, nylon pellets, high density plastics, polytetrafluoroethylenes, rubbers, resins; ceramics, aluminosilicates; glass; sintered bauxite; quartz; aluminum pellets; ground or crushed shells of nuts, walnuts, pecans, almonds, ivory nuts, and brazil nuts; ground or crushed seed shells of seeds of fruits; ground or crushed seed shells of other plants; crushed fruit pits or processed wood materials, materials derived from woods; graphite, petroleum coke, rubber particles, coal and any combination thereof.
9. The method of claim 5 wherein the multifunctional polymer is selected from the group consisting of a polyacrylamide, a polyacrylamide derivative, a polyacrylamide co-polymer, a N-N dimethylacrylamide-AMPS-acryloylmorpholine terpolymer, N-N dimethylacrylamide-AMPS-vinyl pyrollidone terpolymer, tannin-grafted AMPS, lignite-grafted AMPS-acrylonitrile-acrylamide terpolymer, humate-grafted AMPS-diallyldimethylammonium chloride and any combination thereof.
10. The method of claim 5 wherein the viscosifier is selected from the group consisting of diutan gum, xanthan gum, welan gum, cellulose derivatives, polyacrylic acid, polyacrylamide, copolymers thereof and any combination thereof.
11. The method of claim 5 wherein the particulate material is present in the BITS fluid in an amount of from about 40 wt. % to about 90 wt. % based on the total weight of solids.
12. The method of claim 5 wherein the viscosifier is present in the BITS fluid in an amount of from about 0.2 wt. % to about 5 wt. % based on the total weight of solids.
13. The method of claim 5 wherein the multifunctional polymer is present in the BITS fluid in an amount of from about 1 wt. % to about 15 wt. % based on the total weight of solids.
14. The method of claim 5 wherein the BITS fluid further comprises a chelating agent and a clay.
15. The method of claim 14 wherein the chelating agent is selected from the group consisting of tartaric acid, citric acid, oxalic acid, gluconic acid, oleic acid, uric acid and any combination thereof.
16. The method of claim 14 wherein the clay is selected from the group consisting of bentonite, attapulgite, kalonite, meta kalonite, laponite, hectorite, sepiolite and any combination thereof.
17. The method of claim 1 further comprising introducing to the wellbore a cementitious wellbore servicing fluid and allowing the cementititious wellbore servicing fluid to set into a cement sheath wherein the cement sheath has a structural integrity greater than a cement sheath formed without a prior introduction of the BITS fluid to the wellbore.
18. A method of servicing a wellbore experiencing ballooning comprising:
introducing to the wellbore a balloon-inhibiting tunable spacer (BITS) fluid comprising a particulate material, a multifunctional polymer, a viscosifier, a clay and a chelating agent, wherein at least about 1 wt. % of the BITS fluid is retained by the formation and
wherein a reduction in well ballooning is achieved as indicated by (i) a well pressure that is about zero; (ii) a return flow rate of about zero; (iii) a downhole temperature at a depth of a pervious zone remains about constant or (iv) any combination thereof.
19. The method of claim 18 further comprising determining a regain permeability of the formation.
20. The method of claim 18 wherein the BITS fluid has a yield point of from about 5 lbf/100 ft 2 to about 50 lbf/100 ft 2 at a temperature in the range of from about 40° F. to about 400° F.