Methods of propping created fractures and microfractures in tight formation

Patent metadata

Field	Value
Publication number	US-11255176-B2
Application number	US-201515751779-A
Country	US
Kind code	B2
Filing date	Oct 29, 2015
Priority date	Oct 29, 2015
Publication date	Feb 22, 2022
Grant date	Feb 22, 2022

Abstract

A method of propping created fractures and microfractures in tight formation. The method includes injecting into a wellbore a first pad fluid stage; injecting into the wellbore a second pad fluid stage; injecting into the wellbore a diverting agent; and injecting into the wellbore a main proppant slurry stage; wherein the first pad fluid stage includes an aqueous-based fluid at a rate above the fracturing gradient to create a fracture, wherein the second pad fluid stage includes an aqueous-based fluid and a low concentration of a proppant mixture including a slurry of small proppant materials and/or a slurry of conventional proppant materials to extend the fracture and open up secondary induced fractures, and wherein the main proppant slurry stage includes an aqueous-based fluid and a proppant with a larger size than the small proppant particles in the second pad fluid stage.

First claim

What is claimed is:

1. A method of propping fractures in tight formation comprising:
a) injecting into a wellbore a first pad fluid stage comprising a first aqueous-based fluid at a rate above a fracturing gradient to create fractures;
b) injecting into the wellbore a second pad fluid stage comprising a second aqueous-based fluid and a proppant mixture comprising a slurry of small proppant particles comprising 95% w/w of 140 mesh or smaller, at 0.01 to 0.5 lbm/gal;
c) injecting into the wellbore a diverting agent stage including a divergent agent comprising degradable particulates of at least one of polysaccharides, chitins, chitosans, proteins, aliphatic polyesters, poly(lactides), poly(glycolides), poly(.epsilon.-caprolactones), poly(hydroxybutyrates), polyanhydrides, aliphatic polycarbonates, poly(amino acids), poly(ethylene oxides), polyphosphazenes, coated rock salt, and combinations thereof; and
d) repeating steps b and c at least one more time creating proppant packs in the fractures to create one or more propped fractures;
e) after step (d), injecting into the wellbore only one main proppant slurry stage comprising a third aqueous-based fluid and a proppant with larger sized particles than the small proppant particles in the second pad fluid stage, the third aqueous-based fluid including a tackifying agent or a curable resin providing cohesion between a face of the fractures and at least one of the small proppant particles and the larger sized particles, enhancing vertical proppant distribution within the one or more propped fractures, wherein the main proppant slurry stage incorporates a concentration of about 0.1 lbm/gal of the larger sized particles; and
f) during step (e), increasing particle concentrations of the proppant in the main proppant slurry stage and increasing the particle sizes in the main proppant slurry stage from about 150 microns to about 1,000 microns to provide proppant placement and to ensure opening of primary fractures.

2. The method according to claim 1 , wherein steps b) and c) are repeated in a same perforated interval.

3. The method according to claim 1 , wherein the first pad fluid stage comprises a concentration of small proppant materials of about 0.01 to 0.5 lbm/gal, the small proppant materials being about 1 micron to about 100 microns.

4. The method according to claim 1 , wherein the larger sized particles comprise at least one of natural sand, ceramic bauxite proppant, steel balls, glass beads, and polymer composite beads.

5. The method according to claim 1 , wherein the larger sized particles include a coating on their surfaces.

6. The method according to claim 1 , wherein the proppant mixture in the second pad fluid stage and the main proppant slurry stage further comprise a mixture of proppants with different specific gravities, crush strengths, and degradability, such that once injected into the wellbore, the mixture of proppants suspend, settle, form bridges, or pack, to ensure that the fractures remain open with conductivity.

7. The method according to claim 1 , wherein the proppant in the main proppant slurry stage comprises about 5 weight percent to about 10 weight percent of degradable particulates which allows the proppant to remain permeable, or form porous channels.

8. The method according to claim 1 , wherein at least one of the small proppant particles and the larger sized particles is coated with the tackifying agent or the curable resin to provide cohesion between proppant and the one or more propped fractures, thus enhancing vertical proppant distribution within the propped fractures.

9. The method according to claim 8 , wherein the at least one of the small proppant particles and the larger sized particles is coated with the tackifying agent and the tackifying agent further comprises at least one of non-aqueous tackifying agents, aqueous tackifying agents, silyl-modified polyamide compounds, a resin, crosslinkable aqueous polymer compositions, polymerizable organic monomer compositions, consolidating agent emulsions, zeta-potential modifying aggregating compositions, and binders.

10. The method according to claim 8 , wherein the at least one of the small proppant particles and the larger sized particles is coated with the curable resin, the curable resin comprises at least one of two-component epoxy-based resins, novolak resins, polyepoxide resins, phenol-aldehyde resins, urea-aldehyde resins, urethane resins, phenolic resins, furan resins, furan/furfuryl alcohol resins, phenolic/latex resins, phenol formaldehyde resins, polyester resins and hybrids and copolymers thereof, polyurethane resins and hybrids and copolymers thereof, acrylate resins, and mixtures thereof.

11. The method according to claim 1 , wherein at least one of the injection steps is carried out using a pump.

12. The method of claim 1 , wherein the divergent agent comprises degradable particulates including a plurality of: chitins, chitosans, proteins, aliphatic polyesters, poly(.epsilon.-caprolactones), poly(hydroxybutyrates), polyanhydrides, aliphatic polycarbonates, poly(ethylene oxides), polyphosphazenes, and coated rock salt.

13. A method of propping fractures in tight formation comprising:
a) injecting into a wellbore a first pad fluid stage comprising a first aqueous-based fluid at a rate above a fracturing gradient to create fractures;
b) injecting into the wellbore a second pad fluid stage comprising a second aqueous-based fluid and a slurry of small proppant particles of about 1 micron to 100 microns, the slurry comprising a mixture of proppants having different specific gravities, different crush strengths and different degradability;
c) injecting into the wellbore a diverting agent stage including a divergent agent comprising degradable particulates of at least one of chitins, chitosans, proteins, aliphatic polyesters, poly(.epsilon.-caprolactones), poly(hydroxybutyrates), polyanhydrides, aliphatic polycarbonates, poly(amino acids), poly(ethylene oxides), polyphosphazenes, coated rock salt, and combinations thereof;
d) repeating steps b and c at least one more time creating proppant packs in the fractures to create one or more propped fractures; and
e) after step (d), injecting into the wellbore only one main proppant slurry stage comprising a third aqueous-based fluid and a proppant with larger sized particles than the small proppant particles in the second pad fluid stage for propping the fractures, the third aqueous-based fluid including a tackifying agent or a curable resin providing cohesion between a face of the fractures and at least one of the small proppant particles and the larger sized particles, enhancing vertical proppant distribution within the one or more propped fractures, wherein the main proppant slurry stage incorporates a concentration of about 0.1 lbm/gal of the larger sized particles; and
f) during step (e), increasing particle concentrations of the proppant in the main proppant slurry stage and increasing the particle sizes in the main proppant slurry stage from about 150 microns to about 1,000 microns to provide proppant placement and to ensure opening of primary fractures.

14. The method of claim 13 , wherein the degradable particulates degrade by enzymatic reaction.

15. The method of claim 13 , wherein the divergent agent comprises degradable particulates including a plurality of: chitins, chitosans, proteins, aliphatic polyesters, poly(.epsilon.-caprolactones), poly(hydroxybutyrates), polyanhydrides, aliphatic polycarbonates, poly(ethylene oxides), polyphosphazenes, and coated rock salt.

16. The method of claim 15 , wherein the degradab

Assignees

• Halliburton Energy Services Inc

Inventors

• Nguyen Philip D
• Dusterhoft Ronald Glen
• Singh Dipti

Classifications

• C09K8/66

  Compositions based on water or polar solvents (C09K8/64 takes precedence) · CPC title

• C09K8/80

  Compositions for reinforcing fractures, e.g. compositions of proppants used to keep the fractures open · CPC title

• C09K8/68

  containing organic compounds · CPC title

• C09K8/805

  Coated proppants · CPC title

• E21B43/267 Primary

  reinforcing fractures by propping · CPC title