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Publication numberUS20030092584 A1
Publication typeApplication
Application numberUS 10/280,635
Publication dateMay 15, 2003
Filing dateOct 25, 2002
Priority dateNov 13, 2001
Also published asCA2411559A1
Publication number10280635, 280635, US 2003/0092584 A1, US 2003/092584 A1, US 20030092584 A1, US 20030092584A1, US 2003092584 A1, US 2003092584A1, US-A1-20030092584, US-A1-2003092584, US2003/0092584A1, US2003/092584A1, US20030092584 A1, US20030092584A1, US2003092584 A1, US2003092584A1
InventorsJames Crews
Original AssigneeCrews James B.
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Deep water completions fracturing fluid compositions
US 20030092584 A1
Abstract
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/or biodegradable.
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Claims(26)
I claim:
1. A fracturing fluid composition comprising:
i) water;
ii) at least one hydratable polymer;
iii) at least one crosslinking agent;
iv) at least one additional crosslinking delay agent;
v) at least one breaking agent; and
vi) at least one gas hydrate inhibitor.
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, CaCl2 salt, MgCl2 salt, formate brines, polyols, amine glycols, glycol ethers, alcohols, and electrolytes,
kinetic and anti-agglomerate inhibitors selected from the group consisting of copolymers, vinyl polymers, polysaccharides, amides, lactams (such as vinylcaptrolactam, polyvinyl lactam), pyrrolidones, acrylates, fatty acid surfactants, alkyl glucosides, alkyl amines, alkyl phosphonates, alkyl sulphonates, hydrocarbon based dispersants, polycarbonates, amino acids, proteins, glycoproteins, amino carboxylic acids, and
mixtures thereof.
3. The fracturing fluid composition of claim 1 further comprising:
vii) an additional gas hydrate inhibitor different from v); 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, or other guar polymer derivatives.
9. The fracturing fluid composition of claim 1 further comprising at least one additional component selected from the group consisting of pH buffers; biocides; surfactants; non-emulsifiers; anti-foamers; at least one additional, different breaking agent selected from the group consisting of enzyme breakers, oxidizer breakers and mixtures thereof; scale inhibitors; colorants; clay control agents; gel breaker aids; and mixtures thereof.
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 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/m3) 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/m3) of breaking agent; and
from about 0.006 to about 30 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.
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, CaCl2 salt, MgCl2 salt, formate brines, polyols, amine glycols, glycol ethers, alcohols, and electrolytes,
kinetic and anti-agglomerate inhibitors selected from the group consisting of copolymers, vinyl polymers, polysaccharides, amides, lactams (such as vinylcaptrolactam, polyvinyl lactam), pyrrolidones, acrylates, fatty acid surfactants, alkyl glucosides, alkyl amines, alkyl phosphonates, alkyl sulphonates, hydrocarbon based dispersants, polycarbonates, amino acids, proteins, glycoproteins, amino carboxylic acids, 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 v); 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 177° 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, or other guar polymer derivatives.
23. The method of claim 14 where in the fracturing fluid composition the composition further comprises at least one additional component selected from the group consisting of pH buffers; biocides; surfactants; non-emulsifiers; anti-foamers; at least one additional, different breaking agent selected from the group consisting of enzyme breakers, oxidizer breakers, and mixtures thereof; scale inhibitors; colorants; clay control agents; gel breaker aids; and mixtures thereof.
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/m3) 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/m3) of breaking agent; and
from about 0.006 to about 30 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.
Description
CROSS-REFERENCE TO RELATED APPLICATION

[0001] This application claims the benefit of U.S. Provisional Application No. 60/337,714 filed Nov. 13, 2001.

FIELD OF THE INVENTION

[0002] The present invention relates to fluids and methods used in fracturing subterranean formations during hydrocarbon recovery operations, and more particularly relates, in one embodiment, to fluids and methods of fracturing subterranean formations beneath the sea floor and/or where the well bore encounters a wide temperature range.

BACKGROUND OF THE INVENTION

[0003] Hydraulic fracturing is a method of using pump rate and hydraulic pressure to fracture or crack a subterranean formation. Once the crack or cracks are made, high permeability proppant, relative to the formation permeability, is pumped into the fracture to prop open the crack. When the applied pump rates and pressures are reduced or removed from the formation, the crack or fracture cannot close or heal completely because the high permeability proppant keeps the crack open. The propped crack or fracture provides a high permeability path connecting the producing wellbore to a larger formation area to enhance the production of hydrocarbons.

[0004] The development of suitable fracturing fluids is a complex art because the fluids must simultaneously meet a number of conditions. For example, they must be stable at high temperatures and/or high pump rates and shear rates that can cause the fluids to degrade and prematurely settle out the proppant before the fracturing operation is complete. Various fluids have been developed, but most commercially used fracturing fluids are aqueous based liquids that have either been gelled or foamed. When the fluids are gelled, typically a polymeric gelling agent, such as a solvatable polysaccharide is used. The thickened or gelled fluid helps keep the proppants within the fluid. Gelling can be accomplished or improved by the use of crosslinking agents or crosslinkers that promote crosslinking of the polymers together, thereby increasing the viscosity of the fluid.

[0005] The recovery of fracturing fluids may be accomplished by reducing the viscosity of the fluid to a low value so that it may flow naturally from the formation under the influence of formation fluids. Crosslinked gels generally require viscosity breakers to be injected to reduce the viscosity or “break” the gel. Enzymes, oxidizers, and acids are known polymer viscosity breakers. Enzymes are effective within a pH range, typically a 2.0 to 10.0 range, with increasing activity as the pH is lowered towards neutral from a pH of 10.0. Most conventional borate crosslinked fracturing fluids and breakers are designed from a fixed high crosslinked fluid pH value at ambient temperature and/or reservoir temperature. Optimizing the pH for a borate crosslinked gel is important to achieve proper crosslink stability and controlled enzyme breaker activity.

[0006] One difficulty with conventional fracturing fluids is the fact that they tend to emulsify when they come into contact with crude oil, which inhibits the ability to pump them further down hole to the subterranean formation, and/or increases the energy requirements of the pumping operation, in turn raising costs. Various additives are incorporated into fracturing fluids as non-emulsifiers or emulsifier inhibitors and specific examples include, but are not necessarily limited to ethoxylated alkyl phenols, alkyl benzyl sulfonates, xylene sulfonates, alkyloxylated surfactants, ethoxylated alcohols, surfactants and resins, and phosphate esters. Further, certain additives are known which, by themselves, do not act as emulsifiers, but instead enhance the performance of the non-emulsifiers. Various non-emulsifier enhancers include, but are not necessarily limited to alcohol, glycol ethers, polyglycols, aminocarboxylic acids and their salts, bisulfites, polyaspartates, aromatics and mixtures thereof.

[0007] Fracturing fluids also include additives to help inhibit the formation of scale including, but not necessarily limited to carbonate scales and sulfate scales. Such scale cause blockages not only in the equipment used in hydrocarbon recovery, but also can create fines that block the pores of the subterranean formation. Examples of scale inhibitors and/or scale removers incorporated into fracturing fluids include, but are not necessarily limited to polyaspartates; hydroxyaminocarboxylic acid (HACA) chelating agents, such as hydroxyethyliminodiacetic acid (HEIDA), ethylenediaminetetracetic acid (EDTA), diethylenetriaminepentaacetic acid (DTPA), nitrilotriacetic acid (NTA) and other carboxylic acids and their salt forms, phosphonates, and acrylates and mixtures thereof.

[0008] Fracturing fluids that are crosslinked with titanate, zirconate, and/or borate ions (using compounds which generate these ions), sometimes contain additives that are designed to delay crosslinking. Crosslinking delay agents permit the fracturing to be pumped down hole to the subterranean formation before crosslinking begins to occur, thereby permitting more versatility or flexibility in the fracturing fluid. Examples of crosslink delay agents commonly incorporated into fracturing fluids include, but are not necessarily limited to organic polyols, such as sodium gluconate; sodium glucoheptonate, sorbitol, glyoxal, mannitol, glucose, fructose, alkyl glucosides, phosphonates, aminocarboxylic acids and their salts (EDTA, DTPA, etc.) and mixtures thereof.

[0009] Other common additives employed in conventional fracturing fluids include crosslinked gel stabilizers that stabilize the crosslinked gel (typically a polysaccharide crosslinked with titanate, zirconate or borate) for a sufficient period of time so that the pump rate and hydraulic pressure may fracture the subterranean formations. Suitable crosslinked gel stabilizers previously used include, but are not necessarily limited to, sodium thiosulfate, diethanolamine, triethanolamine, methanol, hydroxyethylglycine, tetraethylenepentamine, ethylenediamine and mixtures thereof.

[0010] Additional common additives for fracturing fluids are enzyme breaker (protein) stabilizers. These compounds stabilize the enzymes and/or proteins used in the fracturing fluids to eventually break the gel after the subterranean formation is fractured so that they are still effective at the time it is desired to break the gel. If the enzymes degrade too early they will not be available to effectively break the gel at the appropriate time. Examples of enzyme breaker stabilizers commonly incorporated into fracturing fluids include, but are not necessarily limited to sorbitol, mannitol, glycerol, sulfites, citrates, aminocarboxylic acids and their salts (EDTA, DTPA, NTA, etc.), phosphonates, sulphonates and mixtures thereof.

[0011] Further, many of the common additives previously used discussed above present environmental concerns because they are not readily biodegradable when it becomes necessary to dispose of the fracturing fluid. Biodegradability of the particular components of a fracturing fluid is particularly important when the fluid is used on an offshore platform and the spent fracturing fluid is disposed of into the sea or the fracturing fluid incidentally leaks into the sea during the fracturing operation. Such components are sometimes termed “green” chemistry to denote products that are or decompose to products that are environmentally benign.

[0012] Other concerns about fracturing operations offshore include the facts that water depths can be up to 12,000 feet (3,660 m) with sea floor temperatures as low as 25° F. (−4.0° C.). The reservoir to be fractured can be a total of more than 25,000 feet (7,620 m) from the completion platform. The production reservoir or formation may be at temperatures above 350° F. (177° C.). Many wellbores and associated subsea production pipelines are prone to gas hydrate precipitation and subsequent plugging.

[0013] It would be desirable if multifunctional fracturing fluid compositions could be devised that have suitable properties or characteristics for deep water (off-shore platform) fracturing fluids using biodegradable additives and compounds, and that also inhibit gas hydrates and are operable over a wide temperature range.

SUMMARY OF THE INVENTION

[0014] Accordingly, it is an object of the present invention to provide multifunctional fracturing fluids that can be used in deep water fracturing operations.

[0015] It is another object of the present invention to provide a biodegradable fracturing fluid composition that is inhibited against gas hydrate formation.

[0016] Another object of the present invention to provide a fracturing fluid composition with specialized crosslink delay ability that is operable over a wide temperature range; in one non-limiting embodiment, a difference of about 200° F. (93° C.) or more.

[0017] In carrying out these and other objects of the invention, there is provided, in one form, a method for fracturing a subterranean formation that includes, but is not necessarily limited to:

[0018] a. pumping a fracturing fluid composition down a wellbore to a subterranean formation;

[0019] b. permitting the fracturing fluid composition to gel;

[0020] c. pumping the fracturing fluid composition against the subterranean formation at sufficient rate and pressure to fracture the formation;

[0021] d. breaking the fracturing fluid composition gel; and

[0022] e. subsequently flowing the fracturing fluid composition out of the formation.

[0023] A fracturing fluid composition useful in such a method includes, but is not necessarily limited to:

[0024] i) water;

[0025] ii) at least one hydratable polymer;

[0026] iii) at least one crosslinking agent;

[0027] iv) at least one crosslinking delay agent;

[0028] v) at least one breaking agent; and

[0029] vi) at least one gas hydrate inhibitor.

[0030] Optionally, there may be vii) an additional gas hydrate inhibitor different from v), 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.

[0031] Other components may also be present in the fracturing fluid including, but not necessarily limited to, pH buffers, biocides, surfactants, non-emulsifiers, anti-foamers, additional breaking agents such as enzyme breakers and oxidizer breakers, inorganic scale inhibitors, colorants, clay control agents, gel breaker aids, and mixtures thereof.

BRIEF DESCRIPTION OF THE DRAWINGS

[0032]FIG. 1 is a graph of borate particle crosslinker crosslink delay rate at 75° F. (24° C.) measured as viscosity as a function of time using various proportions of two different types of crosslink delay chemistry;

[0033]FIG. 2 is a graph of borate particle crosslinker crosslink delay rate at 40° F. (4° C.) measured as viscosity as a function of time using various proportions of two different types of crosslink delay chemistry;

[0034]FIG. 3 is a graph of crosslink delay rate at 75° F. (24° C.) measured as viscosity as a function of time using borate-polyol complex crosslink delay agent chemistry;

[0035]FIG. 4 is a graph of crosslink delay rate at 40° F. (4° C.) measured as viscosity as a function of time using borate-polyol complex crosslink delay agent chemistry;

[0036]FIG. 5 is a chart of chart of the temperature effect on crosslinking rate at the 10 minute delay time for FIGS. 1-4, respectively, to compare the systems; and

[0037]FIG. 6 is a graph of borate concentration as a function of pH to show that increases in pH converts the available boron to usable borate ion form.

DETAILED DESCRIPTION OF THE INVENTION

[0038] Deep water completions are commonly “frac packed”. Water depths for these off shore operations can be up to 12,000 feet (3,660 m) deep with sea floor water temperatures as low as 25° F. (−4.0° C.). In contrast, the production reservoir can be at temperatures up to about 350° F. (about 177° C.). Additionally, the reservoir to be fractured can be at a total distance of more than 25,000 feet from the completion platform. Many wellbores and associated subsea production pipelines are prone to gas hydrate precipitation and plugging as the gas hydrate forming species and water are transported through environments of different temperature and pressure from their origin. As noted, offshore environments often necessitate “green chemistry” chemical products that are benign and/or readily biodegradable. Novel fracturing fluid compositions have been discovered which will successfully frac pack deep water and other types of subsea completions, as well as any formation fracturing operation where there is a relatively wide temperature range over the length of the wellbore and/or the total wellbore length from the platform to the reservoir is relatively long. In other words, a fracturing fluid composition is provided that can be varied or modified to meet deep water and other subsea frac pack applications.

[0039] The fracturing fluid composition of this invention generally has the following composition:

[0040] i) water;

[0041] ii) at least one hydratable polymer;

[0042] iii) at least one crosslinking agent;

[0043] iv) at least one crosslinking delay agent;

[0044] v) at least one breaking agent;

[0045] vi) at least one gas hydrate inhibitor; and

[0046] vii) optionally a second gas hydrate inhibitor, where one of the hydrate inhibitors has the ability or characteristic to stay in the aqueous solution phase (e.g. surfactants, alcohols, solvents, etc.) and the other is a polymer (e.g. HEC, HE-300, INHIBEX 101, etc.)

[0047] In various non-limiting embodiments of the invention, the broad and preferred proportions of these various components may be as shown in Table I.

TABLE I
Broad and Narrow Proportions of Fracturing Fluid Components
Component Broad Proportions Preferred Proportions
Water about 70 to about 95 to
99 vol % 99.5 vol %
Hydratable polymer about 10 to about 20 to
60 pptg (kg/m3) 40 pptg (kg/m3)
Crosslinking agent about 0.025 to about 0.04 to
(may optionally function 3.0 vol % 2.0 vol %
also to delay
crosslinking)
Crosslinking delay agent about 0.006 to about 0.012 to
0.5% bw % 0.12% bw %
Breaking agent about 0.1 to about 0.5 to
40 pptg (kg/m3) 20 pptg (kg/m3)
Gas hydrate inhibitor(s) about 0.006 to about 0.25 to
30% bw % 2.0% bw %

[0048] The hydratable polymer may be generally any hydratable polymer known to be used to gel or viscosify a fracturing fluid. In one non-limiting embodiment of the invention, the hydratable polymer is a polysaccharide. In another non-limiting embodiment of the invention, the suitable hydratable polymers include, but are not necessarily limited to, glycol- or glycol ether-based slurry guars, hydroxypropyl guar, carboxymethylhydroxypropyl guar or other guar polymer derivatives.

[0049] In a preferred embodiment of the invention, the hydratable polymer is crosslinked to provide an even greater viscosity or a tighter gel. Any of the common crosslinking agents may be used including, but not necessarily limited to titanate ion, zirconate ion and borate ion. In one non-limiting embodiment of the invention, the preferred crosslinker is borate ion. Borate ion, as well as the other ions, can be generated from a wide variety of sources.

[0050] Because of the wellbore distances involved in deep water completion operations, it is necessary to use crosslink delay additives. For instance, in many deep water operations, it may take from about 1,000 to 12,000, feet (about 305 to 3,660 m) or more of pipe-casing simply to reach the sea floor, in addition to the remaining pipe-casing length to reach the reservoir, which may result in a total pipe length of 25,000 feet (7,620 m) or more. It is important that the polymer gel does not substantially crosslink during this distance en route, but that most crosslinking is delayed until the fracturing fluid has reached or just prior to reaching the formation. Additionally, the crosslink delay additives (as well as all other additives) must be able to perform over the temperature differential expected over the length of the well bore. Such temperature differentials are expected to be about 350° F. (about 194° C.) in one non-limiting embodiment, preferably about 250° F. (about 139° C.), more preferably about 160° F. (about 88° C.), and most preferably about 90° F. (50° C.). The crosslink delay agent should function over a temperature range of from about 350° F. to 25° F. (about 177° C. to −4.0° C.).

[0051] Suitable crosslinking delay agents include, but are not necessarily limited to, slurried borax suspension (commonly used in a 1.0 to 2.5 gptg1 application range, available as XL-3L from Baker Oil Tools), ulexite, colemanite, and other slow dissolving crosslinking borate minerals, and complexes of borate ion, zirconate ion, and titanate ion with sorbitol, mannitol, sodium gluconate, sodium glucoheptonate, glycerol, alpha D-glucose, fructose, ribose; alkyl glucosides (such as AG-6202 available from Akzo Nobel), and other ion complexing polyols; and mixtures thereof. A slurried ulexite suspension known as XL-2LW is available from Baker Oil Tools and is commonly used at an application level of about 0.5 to about 3.0 gptg.

[0052] FIGS. 1 to 5 show the <75° F. (<24° C.) temperature crosslinking rate of two types of crosslink delay chemistry, that is, how cooling a fluid can change the crosslink delay rate FIGS. 1 and 2 present borate mineral particles crosslink delay agent chemistry at 75° F. (24° C.) and 40° F. (4° C.) (note that the XL-2LW is a slurried ulexite particles crosslinker suspension and the BA-5 is a 47% potassium carbonate pH buffer solution). FIGS. 3 and 4 present borate-polyol complex crosslink delay agent chemistry for 75° F. (24° C.) and 40° F. (4° C.) (note that the 12-5-15 represents 12 pptg sodium hydroxide, 5.0 pptg boric acid, and 15 to 20 pptg sodium gluconate polyol). The FIGS. show what the effect of cooling a delayed fracturing fluid down from 75° F. to 40° F. (24° C. to 4° C.) can do to the rate of crosslinking. FIG. 5 shows the 10-minute delay time viscosity to compare the systems. The data shows the borate mineral chemistry can best be delayed by using minimal crosslinker loading and a raise in pH to convert the boron available to a borate form rather than boric acid (see FIG. 6 for the effect pH has on boric acid-borate ion equilibrium). The borate-polyol chemistry can be best controlled for lower temperature by adjustment of the polyol concentration.

[0053] Just as many hydratable polymers and crosslinkers for them are known in the art, there are a wide variety of known gel breakers that would be suitable for use in the methods of this invention. Enzyme breakers that are suitable for use with the present invention include, but are not limited to GAMMANASE 1.0L available from Novozymes, PLEXGEL 10L available from Chemplex, GBW-174L available from Genencor (Bio-Cat distributor), GBW-319 available from Genencor (Bio-Cat distributor), VISCOZYME available from Novozymes, HG-70 available from ChemGen, and mixtures thereof. Oxidizer breakers include, but are not necessarily limited to, chlorites, hypochlorites bromates, chlorates, perchlorates, percarbonates, peroxides, periodates, persulfates, and mixtures thereof.

[0054] Known gas hydrate inhibitors have been used in produced hydrocarbons. There are three general categories of gas hydrate inhibitors: thermodynamic inhibitors, kinetic inhibitors, and anti-agglomerate inhibitors. Thermodynamic inhibitors (e.g. alcohols, glycols, electrolytes, etc.) lower the chemical potential of water and the hydrogen bond energy, which requires additional cooling before hydrates will begin to form, analogous to antifreeze. These inhibitors will also reduce hydrate stability. Kinetic inhibitors and anti-agglomerates do not lower the onset temperature of hydrate formation, but they adsorb on the surface of hydrate microcrystals and significantly alter surface tension at the interface between the hydrate-forming phases These inhibitors prevent a further increase in crystal size and retard formation of large hydrate agglomerates and solid plugs. Kinetic inhibitors can have the effect of spreading any freezing over an extended period of time. Anti-agglomerates typically are polymers that disrupt the crystal organization of development by physically interfering as the crystals form and join one another.

[0055] Suitable thermodynamic inhibitors include, but are not necessarily limited to, NaCl salt, KCl salt, CaCl2 salt, MgCl2 salt, formate brines, polyols (such as glucose, sucrose, fructose, monoethylene glycol, diethylene glycol, triethylene glycol, glycerol, sorbitol, mannitol, methanol, propanol, ethanol), amine glycols (such as triethylene glycol diamine), glycol ethers (such as diethylenemonomethyl ether, ethyleneglycol monobutylether), other solvents, alcohols, and electrolytes, and mixtures thereof.

[0056] Suitable kinetic and anti-agglomerate inhibitors include, but are not necessarily limited to, copolymers (such as INHIBEX 101 (available from ISP Technologies), and HE-300 (a synthetic, divalent ion-tolerant high temperature vinyl polymer available from Drilling Specialties), polysaccharides (such as hydroxyethylcellulose (HEC), starch, and xanthan), amides (such as vinylmethylacetamide), lactams (such as vinylcaptrolactam, polyvinyl lactam), pyrrolidones (such as polyvinyl pyrrolidone), acrylates (such as dimethylethylaminomethacrylate), fatty acid surfactants (such as ethyloxy sorbitan monolaurate, sodium sulfosuccinate, palmitic acid monoglyceride), other surfactants (such as alkyl glucosides, alkyl amines, alkyl phosphonates, alkyl suponates), hydrocarbon based dispersants (such as calcium lignosulfonate, sodium diethylenetriaminepentamethylene phosphonate, sodium ethylenediaminetetramethylene phosphonate, polysuccinates, polyaspartates), polycarbonates, amino acids, proteins, glycoproteins, amino carboxylic acids (such as EDTA, NTA), and mixtures thereof.

[0057] It is permissible that more than one type of gas hydrate inhibitor be used. In one non-limiting embodiment of the invention, at least two gas hydrate inhibitors are used in the fracturing fluid composition, one that would stay in solution phase and one that is a polymer and can become part of a polymer accumulation including, but not necessarily limited to, a filter cake or a proppant pack polymer accumulation typical of frac-pack treatments. The solution phase is important as a gas hydrate inhibitor that can be readily flowed back with reservoir fluids. The polymeric gas hydrate inhibitor can serve as a slower and more prolonged gas hydrate agent during well production. Because the polymeric gas hydrate inhibitor may be part of the filter cake and/or polymer accumulation/residue during and after the treatment, these inhibitors will be produced back over time during production. Polymeric hydrate inhibitors should preferably not be used alone since a majority of the polymer will be trapped during the treatment, but the smaller the polymer size, the more readily it will flow back and be of utility as an anti-agglomerate inhibitor agent. An aqueous phase hydrate inhibitor is most important, and the polymeric inhibitor may be used as long as it is properly designed for plating out during a treatment. The thermodynamic inhibitors and the surfactants, and hydrocarbon dispersants could be the agents that would stay in solution. The copolymers, polysaccharides and proteins could be the agents that would become filtered at the formation face during fracturing operations and become filter cake and/or polymer accumulation within the proppant pack. As expected, it is preferred that the gas hydrate inhibitors be biodegradable or environmentally benign.

[0058] The fracturing fluid composition of this invention can also incorporate additional components, such as pH buffers, biocides, surfactants, non-emulsifiers, anti-foamers, enzyme stabilizers, additional gel breakers such as oxidizer breakers and enzyme breakers, scale inhibitors, gel breaker aids, colorants, clay control agents, and mixtures thereof. In a preferred embodiment of the invention, these additional components are biodegradable. Readily biodegradable biocides include, but are not necessarily limited to, dibromo nitrilopropionamide, (X-CIDE 508 and X-CIDE 509 available from Baker Petrolite), tetrakishydroxymethyl phosphonium sulfate (MAGNACIDE 575 available from Baker Petrolite), isothiazolins, carbamates, chlorhexidine gluconate, triclosan, sorbates, benzoates, propionates, parabens, nitrites, nitrates, bromides, bromates, chlorites, chlorates, hypochlorites, acetates, iodophors, hydroxyl methyl glycinate (Integra® 44 from ISP Technologies), and mixtures thereof. Oxyalkyl polyols can be advantageously employed as non-emulsifiers and/or as water-wetting surfactants. Readily biodegradable non-emulsifier enhancers may include, but are not necessarily limited to, chelants such as polyaspartate, disodium hydroxyethyliminodiacetic (Na2HEIDA), sodium gluconate; sodium glucoheptonate, glycerol, iminodisuccinates, and mixtures thereof.

[0059] Optionally, biodegradable colorants or dyes may be used in the fracturing fluid compositions of this invention to help identify them and distinguish them from other fluids used in hydrocarbon recovery.

[0060] Of course, a proppant is often used in fracturing fluids. Conventional proppants used in conventional proportions may be used with the fluid compositions and methods of this invention. Such conventional proppants include, but are not necessarily limited to, naturally occurring sand grains, man-made or specially engineered coated proppants (e.g. resin-coated sand or ceramic proppants), moderate to high-strength ceramic materials like ECONOPROP®, CARBOLITE®, CARBOPROP® proppants (all available from Carbo Ceramics) sintered bauxite, and mixtures thereof. Proppant materials are generally sorted for sphericity and size to give an efficient conduit for production of hydrocarbons from the reservoir to the wellbore.

[0061] It will be appreciated that it is difficult, if not impossible, to predict with specificity the proportions of the various components in the fracturing fluid compositions of this invention since any particular composition will depend upon a number of complex, interrelated factors including, but not necessarily limited to, the wellbore distance, the temperature differential or range over which the composition will be subjected, the expected pump rates and pressures for the fracturing operation, the particular hydratable polymer used, the particular crosslinking agent used, the particular gel breaker incorporated, the particular crosslink delay agent used, the particular gas hydrate inhibitor(s) employed, and the like.

[0062] The invention will now be further illustrated with respect to certain specific examples which are not intended to limit the invention, but rather to provide more specific embodiments as only a few of many possible embodiments.

EXAMPLE 1

[0063] One embodiment of the fluid composition of the invention for use in 5,000 feet (1,520 m) of deep water (total distance from the platform to the reservoir of 22,000 feet (6,700 m)) and 250° F. (121° C.) reservoir temperature may be as follows:

[0064] 1. From about 30.0 to about 40.0 pptg (about 3.6 to about 4.8 kg/m3) fracturing polymers and crosslinker, in one non-limiting embodiment preferably a borate crosslinked guar.

[0065] 2. From about 0.5 to about 1.0 gptg sodium glucoheptonate and 1.0 to about 2.0 gptg XL-2LW borate mineral crosslinkers. For effective crosslink delay in 5,000 feet (1,520 m) of water and 22,000 feet (6,700 m) total depth to the formation:

[0066] a) About 0.6 gptg sodium glucoheptonate, and

[0067] b) About 1.25 gptg XL-2LW for 250° F. (121° C.) formation temperature.

[0068] 3. From about 2.5 to about 3.0 gptg BA-5 pH buffer for crosslinking borate ions.

[0069] 4. From about 1.0 to about 3.0 gptg ST-100 or ST-101 strong water wetting surfactant.

[0070] 5. From about 0.05 to about 0.1 gptg X-CIDE 508 for biocide.

[0071] 6. From about 1.0 to about 5.0 pptg (about 0.12 to about 0.60 kg/M3) STIM-440 non-emulsifier available from Mayco Wellchem.

[0072] 7. From about 0.5 to about 2.0 gptg Si-203 scale inhibitor from Baker Oil Tools.

[0073] 8. From about 2.0 to about 5.0% by weight (bw) KCl and about 1.0 to about 2.0 gptg CS-7 clay control agents.

[0074] 9. From about 1.0 to 5.0 pptg (about 0.12 to about 0.60 kg/m3) sodium bromate or sodium salts of HEDTA or NTA as gel breakers.

[0075] 10. To prevent gas hydrate formation:

[0076] a) About 5.0 gptg ethylene glycol monobutyl ether, and

[0077] b) About 5.0 gptg INHIBEX-101 available from ISP Technologies.

[0078] 12.0 to 14 ppa proppant (pounds proppant added per 1.0 fluid gallon volume) (0 to 1.7 kg/l).

EXAMPLE 2

[0079] Another non-limiting embodiment of the fluid composition of the invention for use in 1,000 feet (305 m) of deep water (total distance from the platform to the reservoir of 8,000 feet or 2438 m) and 150° F. (65° C.) reservoir temperature may be as follows:

[0080] 1. From about 20.0 to about 30.0 pptg (about 2.4 to about 3.6 kg/m3) fracturing polymers and crosslinker, in one non-limiting embodiment preferably a borate crosslinked guar.

[0081] 2. For effective crosslink delay in 1,000 feet (305 m) of water and 8,000 feet (2,438 m) total depth to the formation:

[0082] a) About 0.5 gptg XL-3L for cool water crosslink delay, and

[0083] b) About 0.4 gptg XL-2LW for 150° F. (65° C.) formation temperature that the fracturing fluid will heat up to.

[0084] 3. From about 0.75 to about 1.0 gptg BA-5 pH buffer for crosslinking borate ions.

[0085] 4. From about 3.0 to about 8.0 pptg (about 0.36 to about 0.96 kg/m3) STIM-440 non-emulsifier, water wetting agent.

[0086] 5. From about 2.0 to about 5.0% bw KCl and about 1.0 to about 2.0 gptg CS-7 clay control agent.

[0087] 6. From about 0.05 to about 0.1 gptg MAGNACIDE 575 biocide.

[0088] 7. From about 0,5 to about 2.0 gptg A-5D scale inhibitor, gas hydrate inhibitors, and non-emulsifier aids from Donlar Corporation.

[0089] 8. From about 2.0 to about 4.0 gptg alpha D-glucose breaker aid.

[0090] 9. From about 0.5 to 2.0 pptg (about 0.06 to about 0.24 kg/m3) sodium persulfate as gel breaker.

[0091] 10. To prevent gas hydrate formation:

[0092] a) About 5.0 gptg ethylene glycol monobutyl ether, and

[0093] b) About 10.0 pptg (1.2 kg/m3) polyvinyl pyrrolidone K-30 available from ISP Technologies.

[0094] 11.0 to 14 ppa proppant (pounds proppant added per 1.0 fluid gallon volume) (0 to 1.7 kg/l).

EXAMPLE 3

[0095] Another non-limiting embodiment of the fluid composition of the invention for use in 5,000 feet (1520 m) of deep water (total distance from the platform to the reservoir of 15,000 feet or 4560 m) and 175° F. (79° C.) reservoir temperature may be as follows:

[0096] 1. About 30.0 pptg (about 3.6 kg/m3) guar fracturing polymer.

[0097] 2. For effective crosslink delay in 5,000 feet (1520 m) of water and 15,000 feet (4560 m) total depth to the formation:

[0098] a) About 0.5 gptg XL-2LW for 175° F. (79° C.) formation temperature that the fracturing fluid will heat up to.

[0099] 3. From about 1.0 gptg BA-5 pH buffer for crosslinking borate ions.

[0100] 4. From about 1.0 to 2.0 gptg AG-6206 alkyl glucoside (from Akzo Nobel) water wetting surfactant.

[0101] 5. From about 2.0 bw KCl and about 2.0 gptg Claprotek CF (choline bicarbonate available from CESI Chemicals) clay control agent.

[0102] 6. From about 0.2 to about 0.5 gptg Integra 44 biocide.

[0103] 7. From about 2.0 to about 4.0 gptg NE-200E non-emulsifier from Baker Oil Tools

[0104] 8. From about 2.0 to about 4.0 gptg sorbitol breaker aid.

[0105] 9. From about 4.0 to 12.0 pptg (about 0.48 to about 1.44 kg/M3) sodium percarbonate as gel breaker.

[0106] 10. To prevent gas hydrate formation:

[0107] a) About 5.0 gptg Inhibex 101 available from ISP Technologies, and

[0108] b) About 5.0 gptg XTJ-504 (triethylene glycol diamine available from Huntsman Chemicals).

[0109] 11.0 to 14 ppa proppant (0 to 1.7 kg/l).

EXAMPLE 4

[0110] Another non-limiting embodiment of the fluid composition of the invention for use in 10,000 feet (3040 m) of deep water (total distance from the platform to the reservoir of 25,000 feet or 7600 m) and 200° F. (93° C.) reservoir temperature may be as follows:

[0111] 1. About 30.0 pptg (about 3.6 kg/m3) guar fracturing polymers.

[0112] 2. For effective crosslink delay in 10,000 feet (3040 m) of water and 25,000 feet (7600 m) total depth to the formation:

[0113] a) About 0.6 gptg XL-2LW for 200° F. (93° C.) formation temperature that the fracturing fluid will heat up to.

[0114] 3. About 3.0 gptg BA-5 pH buffer for crosslinking borate ions.

[0115] 4. About 1.0 gptg AG-6206 alkyl glucoside (from Akzo Nobel) water wetting surfactant.

[0116] 5. About 5.0 bw KCl and about 2.0 gptg Claprotek CF (choline bicarbonate available from CESI Chemicals) clay control agent.

[0117] 6. From about 0.5 to about 1.0 gptg Integra 44 biocide.

[0118] 7. About 5.0 gptg NE-200E non-emulsifier, scale inhibitor, and crosslink delay agent from Baker Oil Tools

[0119] 8. From about 8.0 to 16.0 pptg (about 0.96 to about 1.92 kg/M3) sodium chlorite as gel breaker.

[0120] 9. To prevent gas hydrate formation:

[0121] a) About 5.0 gptg ethyloxy sorbitan monolaurate, and

[0122] b) About 5.0 gptg—Inhibex 101 available from ISP Technologies.

[0123] c) About 10.0 gptg ethanol

[0124] 10. From 0 to 14 ppa proppant (0 to 1.7 kg/l).

EXAMPLE 5

[0125] Another non-limiting embodiment of the fluid composition of the invention for use in 10,000 feet (3040 m) of deep water (total distance from the platform to the reservoir of 25,000 feet or 7600 m) and 200° F. (93° C.) reservoir temperature may be as follows:

[0126] 1. About 30.0 pptg (about 3.6 kg/m3) guar fracturing polymers.

[0127] 2. For effective crosslink delay in 10,000 feet (3040 m) of water and 25,000 feet (7600 m) total depth to the formation the crosslinker solution comprised of:

[0128] a) About 6.0 gptg fresh water

[0129] b) About 5.0 pptg boric acid cosslinker

[0130] c) About 12.0 pptg sodium hydroxide

[0131] d) About 25.0 pptg sodium gluconate with a crosslinker solution yield of about 9.0 gptg.

[0132] 3. About 2.0 gptg AG-6206 alkyl glucoside (from Akzo Nobel) water wetting surfactant.

[0133] 4. About 7.0 bw KCl and about 4.0 gptg TMAC (tetramethyl ammonium chloride available from Special Products) clay control agent.

[0134] 5. From about 0.5 to about 1.0 gptg Integra 44 biocide.

[0135] 6. About 5.0 pptg (about 0.6 kg/M3) Stim 440 non-emulsifier.

[0136] 7. From about 8.0 to 16.0 pptg (about 0.96 to about 1.92 kg/M3) sodium chlorite as gel breaker.

[0137] 8. To prevent gas hydrate formation:

[0138] a) About 5.0 pptg (about 0.6 kg/m3) hydroxyethylcellulose, and

[0139] b) About 10.0 gptg HE-300 (available from Drilling Specialties)

[0140] c) About 10.0 gptg propylene glycol

[0141] d) About 10.0 gptg ethanol

[0142] 9. From 0 to 14 ppa proppant (0 to 1.7 kg/l).

[0143] In the foregoing specification, the invention has been described with reference to specific embodiments thereof, and is expected to be demonstrated as effective in fracturing subterranean formations in deep water completion operations. The components and combinations discussed would be expected to work in commercial fracturing fluids. However, it will be evident that various modifications and changes can be made to the fracturing fluid compositions without departing from the broader spirit or scope of the invention as set forth in the appended claims. Accordingly, the specification is to be regarded in an illustrative rather than a restrictive sense. For example, specific combinations of or proportions of components falling within the claimed parameters, but not specifically identified or tried in particular compositions, are anticipated and expected to be within the scope of this invention.

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Classifications
U.S. Classification507/200
International ClassificationC09K8/68
Cooperative ClassificationC09K8/685, C09K2208/22, C09K2208/20
European ClassificationC09K8/68B
Legal Events
DateCodeEventDescription
Oct 25, 2002ASAssignment
Owner name: BAKER HUGHES INCORPORATED, TEXAS
Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNOR:CREWS, JAMES B.;REEL/FRAME:013448/0240
Effective date: 20021024