U.S. patent application number 10/280635 was filed with the patent office on 2003-05-15 for deep water completions fracturing fluid compositions.
Invention is credited to Crews, James B..
Application Number | 20030092584 10/280635 |
Document ID | / |
Family ID | 23321698 |
Filed Date | 2003-05-15 |
United States Patent
Application |
20030092584 |
Kind Code |
A1 |
Crews, James B. |
May 15, 2003 |
Deep water completions fracturing fluid compositions
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.
Inventors: |
Crews, James B.; (Willis,
TX) |
Correspondence
Address: |
PAUL S MADAN
MADAN, MOSSMAN & SRIRAM, PC
2603 AUGUSTA, SUITE 700
HOUSTON
TX
77057-1130
US
|
Family ID: |
23321698 |
Appl. No.: |
10/280635 |
Filed: |
October 25, 2002 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
60337714 |
Nov 13, 2001 |
|
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Current U.S.
Class: |
507/200 |
Current CPC
Class: |
C09K 2208/20 20130101;
C09K 2208/22 20130101; C09K 8/685 20130101 |
Class at
Publication: |
507/200 |
International
Class: |
E21B 001/00 |
Claims
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, CaCl.sub.2 salt, MgCl.sub.2 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.degree. to about 30.degree. F. (about 1490 to about
-1.degree. 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/m.sup.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.sup.3) 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.degree. F. (50.degree. 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.sub.2 salt, MgCl.sub.2
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.degree. to about 25.degree. F.
(about 177.degree. to about -4.0.degree. 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/m.sup.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.sup.3) 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.degree. F. (50.degree.
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.degree. F. to about
25.degree. F. (173.degree. C. to about -4.0.degree. 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.degree. F. (-4.0.degree. 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.degree. F.
(177.degree. 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.degree. F.
(93.degree. 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.degree. F. (24.degree. 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.degree. F. (4.degree. 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.degree. F.
(24.degree. 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.degree. F.
(4.degree. 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.degree. F. (-4.0.degree. C.). In contrast, the production
reservoir can be at temperatures up to about 350.degree. F. (about
177.degree. 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.
1TABLE 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/m.sup.3) 40 pptg (kg/m.sup.3)
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/m.sup.3) 20 pptg (kg/m.sup.3) 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.degree.
F. (about 194.degree. C.) in one non-limiting embodiment,
preferably about 250.degree. F. (about 139.degree. C.), more
preferably about 160.degree. F. (about 88.degree. C.), and most
preferably about 90.degree. F. (50.degree. C.). The crosslink delay
agent should function over a temperature range of from about
350.degree. F. to 25.degree. F. (about 177.degree. C. to
-4.0.degree. 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 gptg.sup.1 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. gptg=gallons per thousand gallons.
The same numerical values can be expressed as liters per thousand
liters, m.sup.3 per thousand m.sup.3, etc.
[0052] FIGS. 1 to 5 show the <75.degree. F. (<24.degree. 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.degree. F. (24.degree. C.) and
40.degree. F. (4.degree. 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.degree. F. (24.degree. C.) and 40.degree. F. (4.degree. 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.degree. F. to 40.degree. F. (24.degree. C. to
4.degree. 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, CaCl.sub.2 salt,
MgCl.sub.2 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.RTM. 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 (Na.sub.2HEIDA),
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.RTM.,
CARBOLITE.RTM., CARBOPROP.RTM. 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.degree.
F. (121.degree. 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/m.sup.3) 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.degree. F. (121.degree.
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/M.sup.3) 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/m.sup.3) 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.degree. F. (65.degree. 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/m.sup.3) 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.degree. F. (65.degree. 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/m.sup.3) 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/m.sup.3) 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/m.sup.3) 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.degree. F. (79.degree. C.) reservoir temperature may be
as follows:
[0096] 1. About 30.0 pptg (about 3.6 kg/m.sup.3) 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.degree. F. (79.degree. 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/M.sup.3) 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.degree. F. (93.degree. C.) reservoir temperature may be
as follows:
[0111] 1. About 30.0 pptg (about 3.6 kg/m.sup.3) 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.degree. F. (93.degree. 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/M.sup.3) 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.degree. F. (93.degree. C.) reservoir temperature may be
as follows:
[0126] 1. About 30.0 pptg (about 3.6 kg/m.sup.3) 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/M.sup.3) Stim 440
non-emulsifier.
[0136] 7. From about 8.0 to 16.0 pptg (about 0.96 to about 1.92
kg/M.sup.3) sodium chlorite as gel breaker.
[0137] 8. To prevent gas hydrate formation:
[0138] a) About 5.0 pptg (about 0.6 kg/m.sup.3)
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.
* * * * *