Deep water completions fracturing fluid compositions
It has been discovered that fracturing fluid compositions can be designed for successful deep water completion fracturing fluid operations. These fluids must be pumped relatively long distances from offshore platforms to the reservoir, and they are often subjected to a wide temperature range. Under these conditions, it is necessary to inhibit the formation of gas hydrates in the fracturing fluid compositions, as well as to delay the crosslinking of the gels that are formed to increase the viscosity of the fluids prior to fracturing the formation. Preferably, two different gas hydrate inhibitors are used to ensure placement of a gas hydrate inhibitor in most parts of the operation. In addition, as with all offshore or deep water hydrocarbon recovery operations, it is important that the components of the fracturing fluid compositions be environmentally benign and biodegradable.
1 . A fracturing fluid composition comprising:
i) water;
ii) at least one hydratable polymer;
iii) at least one crosslinking agent;
iv) at least one crosslinking delay agent;
v) at least one breaking agent; and
vi) at least one gas hydrate inhibitor in the absence of polyglycolpolyamines.
2 . The fracturing fluid composition of claim 1 where the gas hydrate inhibitor is selected from the group consisting of:
thermodynamic inhibitors selected from the group consisting of NaCl salt, KCl salt, CaCl 2 salt, MgCl 2 salt, NaBr2 salt, formate brines, polyols, glycols, glycerols, glycol ethers, alkyl and cyclic esters of alcohols, saccharides, solvents, alcohols, sugar alcohols, and electrolytes,
kinetic and anti-agglomerate inhibitors selected from the group consisting of polysaccharides, lactams, pyrrolidones, fatty acid salts, ethoxylated alcohols, propoxylated alcohols, alkyl glucosides, alkyl polyglucosides, alkyl sulfates, alkyl sulfonates, alkyl aromatic sulfonates, sorbitan esters, ethoxylated sorbitan esters, polyglycerol esters of fatty acids, alkyl betaines, alkyl amino betaines, amino acids, proteins, iminodisuccinates, polyaspartates, and
mixtures thereof.
3 . The fracturing fluid composition of claim 1 further comprising:
vii) an additional gas hydrate inhibitor different from vi);
where one of the gas hydrate inhibitors remains in the aqueous phase and the other gas hydrate inhibitor is a polymer that at least temporarily becomes part of a polymer accumulation.
4 . The fracturing fluid composition of claim 1 where the crosslinking delay agent can function over a temperature range from about 300° to about 30° F. (about 1490 to about −1° C.).
5 . The fracturing fluid composition of claim 1 where the crosslinking agent iii) and the crosslinking delay agent iv) is a single component.
6 . The fracturing fluid composition of claim 5 where the single component is selected from the group consisting of slurried borax suspensions, ulexite, colemanite; complexes of borate ion, zirconate ion and/or titanate ion with a polyol selected from the group of sorbitol, mannitol, sodium gluconate, sodium glucoheptonate, glycerol, alpha D-glucose, fructose, ribose, alkyl glucosides, and mixtures thereof.
7 . The fracturing fluid composition of claim 1 where the hydratable polymer is a polysaccharide.
8 . The fracturing fluid composition of claim 7 where the hydratable polymer is selected from the group consisting of guar, hydroxypropyl guar, carboxymethylhydroxypropyl guar, and other guar polymer derivatives.
9 . The fracturing fluid composition of claim 1 where the fracturing fluid composition does not form gas hydrates at pressures between about 1000 to about 10,000 psi (about 6.9 to about 69 MPa) and temperatures below about 45° F. for at least 24 hours.
10 . The fracturing fluid composition of claim 1 further comprising:
viii) an additional crosslinking delay agent different from iv).
11 . The fracturing fluid composition of claim 1 where the crosslinking agent is selected from the group consisting of titanate ion, zirconate ion, borate ion, and mixtures thereof.
12 . The fracturing fluid composition of claim 1 where the breaking agent is selected from the group consisting of saccharide breakers, enzyme breakers, oxidizer breakers, and mixtures thereof.
13 . The fracturing fluid composition of claim 1 further comprising:
from about 10 to about 60 pptg (about 1.2 to about 7.2 kg m 3 ) of hydratable polymer;
from about 0.025 to about 3.0 volume % of crosslinking and delaying agent;
from about 0.006 to about 0.5 bw % of crosslinking delay agent;
from about 0.1 to about 40.0 pptg (about 0.072 to about 4.8 kg/m 3 ) of breaking agent; and
from about 0.006 to about 60 bw % of gas hydrate inhibitor.
14 . A method for fracturing a subterranean formation comprising:
a. pumping a fracturing fluid composition down a wellbore to a subterranean formation;
b. permitting the fracturing fluid composition to gel;
c. pumping the fracturing fluid composition against the subterranean formation at sufficient rate and pressure to fracture the formation;
d. breaking the fracturing fluid composition gel;
e. subsequently flowing the fracturing fluid composition out of the formation;
where the fracturing fluid composition comprises:
i) water;
ii) at least one hydratable polymer;
iii) at least one crosslinking agent;
iv) at least one crosslinking delay agent;
v) at least one breaking agent; and
vi) at least one gas hydrate inhibitor in the absence of polyglycolpolyamines.
15 . The method of claim 14 where at least part of the wellbore extends from an offshore platform to a sea floor where the distance from the offshore platform to the sea floor is at least 1,000 feet (304 m), and where the temperature differential over the length of the wellbore from the sea floor to the subterranean formation is at least about 90° F. (50° C.).
16 . The method of claim 14 where in the fracturing fluid composition the gas hydrate inhibitor is selected from the group consisting of:
thermodynamic inhibitors selected from the group consisting of NaCl salt, KCl salt, CaCl 2 salt, MgCl 2 salt, NaBr2 salt, formate brines, polyols, glycols, glycerols, glycol ethers, alkyl and cyclic esters of alcohols, saccharides, solvents, alcohols, sugar alcohols, and electrolytes,
kinetic and anti-agglomerate inhibitors selected from the group consisting of polysaccharides, lactams, pyrrolidones, fatty acid salts, ethoxylated alcohols, propoxylated alcohols, alkyl glucosides, alkyl polyglucosides, alkyl sulfates, alkyl sulfonates, alkyl aromatic sulfonates, sorbitan esters, ethoxylated sorbitan esters, polyglycerol esters of fatty acids, alkyl betaines, alkyl amino betaines, amino acids, proteins, iminodisuccinates, polyaspartates, and
mixtures thereof.
17 . The method of claim 14 where in the fracturing fluid composition, the composition further comprises:
vii) an additional gas hydrate inhibitor different from vi);
where one of the gas hydrate inhibitors remains in the aqueous phase and the other gas hydrate inhibitor is a polymer that at least temporarily becomes part of a polymer accumulation.
18 . The method of claim 14 where in the fracturing fluid composition the crosslinking delay agent can function over a temperature range from about 350° to about 25° F. (about 1770 to about −4.0° C.).
19 . The method of claim 14 where in the fracturing fluid composition the crosslinking agent iii) and the crosslinking delay agent iv) is a single component.
20 . The method of claim 19 where in the fracturing fluid composition the single component is selected from the group consisting of slurried borax suspensions, ulexite, colemanite, complexes of borate ion, zirconate ion and/or titanate ion with a polyol selected from the group of sorbitol, mannitol, sodium gluconate, sodium glucoheptonate, glycerol, alpha D-glucose, fructose, ribose, alkyl glucosides, and mixtures thereof.
21 . The method of claim 14 where in the fracturing fluid composition the hydratable polymer is a polysaccharide.
22 . The method of claim 21 where the hydratable polymer is selected from the group consisting of a guar, hydroxypropyl guar, carboxymethylhydroxypropyl guar, and other guar polymer derivatives.
23 . The method of claim 14 where in the fracturing fluid composition where the fracturing fluid composition does not form gas hydrates at pressures between about 1000 to about 10,000 psi (about 6.9 to about 69 MPa) and temperatures below about 45° F. for at least 24 hours.
24 . The method of claim 14 where in the fracturing fluid composition, the composition further comprises:
viii) an additional crosslinking delay agent different from iv).
25 . The method of claim 14 where the fracturing fluid further comprising:
from about 10 to about 60 pptg (about 1.2 to about 7.2 kg/m 3 ) of hydratable polymer;
from about 0.025 to about 3.0 volume % of crosslinking agent;
from about 0.006 to about 0.5 bw % of crosslinking delay agent;
from about 0.1 to about 40.0 pptg (about 0.072 to about 4.8 kg/m 3 ) of breaking agent; and
from about 0.006 to about 60 bw % of gas hydrate inhibitor.
26 . A method for fracturing a subterranean formation comprising:
a. pumping a fracturing fluid composition down a wellbore to a subterranean formation, where the temperature differential over the length of the wellbore is at least about 90° F. (50° C.);
b. permitting the fracturing fluid composition to gel;
c. pumping the fracturing fluid composition against the subterranean formation at sufficient rate and pressure to fracture the formation;
d. breaking the fracturing fluid composition gel;
e. subsequently flowing the fracturing fluid composition out of the formation;
where the fracturing fluid composition comprises:
i) water;
ii) at least one hydratable polymer;
iii) at least one crosslinking agent, where the crosslinking delay agent can function over a temperature range from about 350° F. to about 25° F. (173° C. to about 4.0° C.);
iv) at least one crosslinking delay agent;
v) at least one breaking agent; and
vi) at least one gas hydrate inhibitor in the absence of polyglycolpolyamines.