FIELD OF THE INVENTION
[0001] The present disclosure relates to a sea water-based fracturing fluid. The
present disclosure also relates to a method of producing a fracturing fluid for
fracturing of subterranean formation.
[0002] The present disclosure further relates to a method 5 thod of using fracturing fluid
for fracturing subterranean formations using hard mix water.
BACKGROUND
[0003] Hydraulic fracturing operations are carried out on oil and gas wells to
increase the flow of oil and natural gas from subterranean formations. In this
10 operation, a viscous fracturing fluid is injected through a wellbore into the
subterranean formation at a pressure and flow rate sufficient to overcome the
overburden stress and to initiate a fracture in the formation. Propping agents are
usually added to the fracturing fluid to prevent the created fractures from closing
back down upon itself after the fracturing fluid flows back into the well and the
15 pressure is released. The proppant filled fractures result in permeable channels
allowing petroleum to seep through the fractures into the wellbore from where it is
pumped to the surface. The most commonly used proppant is sand.
[0004] Fracturing fluids in common use include various aqueous gels and
hydrocarbon gels. In offshore operations, the fracturing fluid can be prepared
20 utilizing sea water to hydrate a gelling agent to form a viscous aqueous fluid. To
promote adequate viscosity at increased well depths, cross-linking agents such as
borate ion releasing compounds can be incorporated into the fracturing fluids. Sea
water contains more dissolved ions than fresh water which form insoluble
precipitates at pH ≥ 9.5 (required pH for good borate cross linking for wells having
25 bottom hole temperature up to 120oC). The presence of solid precipitates reduces the
proppant pack conductivity and ultimately the productivity of the fracturing
operations.
3
[0005] WO 2001083946 A1 discloses a fracturing fluid comprising an
amphoteric surfactant, specifically a betaine surfactant and an organic electrolyte or
an alcohol in an aqueous medium.
[0006] US 6911419 B2 discloses sea water-based cross-linked fracturing fluids
and methods of preparing and using the fluids in fracturing subterranean 5 nean formations
penetrated by well bores and having temperatures above about 200° F.
[0007] EP 0594363 A1 discloses a fracturing fluid comprises sea water, a
polysaccharide polymer, a borate cross-linking agent and an alkaline agent present in
a quantity sufficient to maintain the pH of the fracturing fluid above 9.5.
10 [0008] EP 0528461 B1 discloses a method of fracturing a selected subterranean
formation at temperature above 93° C (200° F).
[0009] Prior art methods describe the removal of solid precipitates in the sea
water by filtration. However, the proper disposal of precipitates like magnesium
hydroxide and other salts creates additional operational costs as well as
15 environmental challenges. Thus, there is a need for a sea water-based fracturing fluid
that avoids precipitate formation.
SUMMARY
[00010] The present disclosure relates to a fracturing fluid comprising: sea water;
biocide; clay hydration suppressant; gel stabilizing agent; water softener; low pH
20 buffering agent; high pH buffering agent; gelling agent; non emulsifier; surfactant;
gel breaker; and cross linker. The fracturing fluid of the present disclosure optionally
comprises of low temperature breaker.
[00011] The present disclosure relates to a method of producing a fracturing fluid
for fracturing of subterranean formation.
25 [00012] Further, the present disclosure relates to a method of using fracturing
fluid for fracturing subterranean formations using hard mix water.
[00013] These and other features, aspects, and advantages of the present
disclosure will become better understood with reference to the following description.
4
This statement is provided to introduce a selection of concepts in simplified form.
This statement is not intended to identify key features or essential features of the
subject matter, nor is it intended to be used to limit the scope of the subject matter.
BRIEF DESCRIPTION OF THE DRAWINGS
[00014] The above and other features, aspects, 5 s, and advantages of the subject
matter will be better understood with regard to the following description, appended
claims, and accompanying drawings where:
[00015] Figure 1 shows the plot of viscosity (cp) at 117 s-1 with respect to time
(min).
10 [00016] Figure 2 shows the plot of pH with respect to the dilution of formation
water.
DETAILED DESCRIPTION
[00017] The present invention now will be described more fully hereinafter.
Indeed, the invention may be embodied in many different forms and should not be
15 construed as limited to the embodiments set forth herein; rather, these embodiments
are provided so that this disclosure will satisfy applicable legal requirements. As
used in the specification, and in the appended claims, the singular forms “a”, “an”,
“the”, include plural referents unless the context clearly dictates otherwise.
[00018] The present disclosure relates to a fracturing fluid comprising: sea water;
20 biocide; clay hydration suppressant; gel stabilizing agent; water softener; low pH
buffering agent; high pH buffering agent; gelling agent; non emulsifier; surfactant;
gel breaker; and cross linker. The fracturing fluid of the present disclosure optionally
comprises of low temperature breaker.
[00019] In an embodiment, the fracturing fluid comprising: 88 to 97% (v/v) of sea
25 water; 0.01 to 0.1% (v/v) of biocide; 1 to 5 % (w/v) of clay hydration suppressant;
0.08 to 0.4% (w/v) of gel stabilizing agent; 0.1 to 2% (w/v) of water softener; 0.1 to
0.3% (v/v) of low pH buffering agent; 0.5 to 1.5% (w/v) of high pH buffering agent;
0.2 to 1% (w/v) of gelling agent; 0.1 to 1% (v/v) of non emulsifier; 0.1 to 1% (v/v) of
5
surfactant; 0.001 to 0.1% (w/v) of gel breaker; and 0.017 to 0.042% (w/v) of cross
linker.
[00020] In another embodiment, the fracturing fluid comprising: 88 to 96% (v/v)
of sea water; 0.01 to 0.1% (v/v) of biocide; 1 to 5 % (w/v) of clay hydration
suppressant; 0.08 to 0.4% (w/v) of gel stabilizing agent; 0.1 to 2% (w/5 v) of water
softener; 0.1 to 0.3% (v/v) of low pH buffering agent; 0.5 to 1.5% (w/v) of high pH
buffering agent; 0.2 to 1% (w/v) of gelling agent; 0.1 to 1% (v/v) of non emulsifier;
0.1 to 1% (v/v) of surfactant; 0.001 to 0.1% (w/v) of gel breaker; 0.01 to 0.06% (v/v)
of low temperature breaker; and 0.017 to 0.042% (w/v) of cross linker.
10 [00021] The fracturing fluids provide a medium for bacterial growth due to the
presence of organic constituents. As the bacteria grow, they secrete enzymes that
break down the gelling agent, which reduces the viscosity of the fracturing fluid.
Reduced viscosity translates into poor proppant placement and poor fracturing
performance. To alleviate this degradation in performance, biocides are added to the
15 mixing tanks before the water is added and then mixed with polymeric gelling agent
to kill any existing microorganisms (e.g., sulphate-reducing bacteria, slim-forming
bacteria, algae) and to inhibit bacterial growth and enzyme production. The biocide
used in the present disclosure is selected from the group consisting of formaldehyde,
gluteraldehyde, chlorophenates, quaternary amines, isothiazoline, 2-bromo-2-nitrilo,
20 3-propanedol, 2,2-dibromo-3-nitrilopropionamide, 2-bromo-3-nitrilopropionamide
and mixtures thereof. The biocide is present in the fracturing fluid in an amount in
the range of from 0.01 to 0.1% v/v of the fracturing fluid, preferably from 0.01 to
0.05% v/v of the fracturing fluid, and most preferably 0.03% v/v of the fracturing
fluid.
25 [00022] Clays are layered particles averaging 2μm in size. Negatively charged
particles result when the charge balance between positive ion and negative ion is
disrupted through displacement of cations or breaking of the particles. Cations,
surround the clay particle and create a positively charged cloud. Such particles repel
6
each other and are prone to migration. Once clay particles are dispersed, the particles
can block pore spaces in the rock and reduce permeability. Chemicals are used to
stabilize clays and fines. These function by being adsorbed on the minerals to be
stabilized usually by electrostatic attraction or ion exchange. Clay hydration
suppressants are used to stabilize clays and prevent swelling. The 5 e clay hydration
suppressant used in the present disclosure is selected from the group consisting of
inorganic salts, preferably KCl, NaCl, KBr, Al2Cl3 and mixtures thereof. The clay
hydration suppressant is present in the fracturing fluid in an amount in the range of 1
to 5% w/v of the fracturing fluid, preferably 1 to 3% w/v of the fracturing fluid, and
10 most preferably 2% w/v of the fracturing fluid.
[00023] Gel stabilizing agents are used to prevent premature degradation of the
fracturing fluid by oxidants at high temperatures. Oxygen is unavoidably placed in
fracturing fluids through dissolution of air. The gel stabilizing agent used in the
present disclosure is selected from the group consisting of sodium thiosulphate,
15 sodium sulfite, sodium erythroborate, methanol, thiourea and mixtures thereof. The
most preferred gel stabilizing agent used in the present disclosure is sodium
thiosulphate. The gel stabilizing agent is present in the fracturing fluid in an amount
in the range of from 0.08 to 0.4% w/v of the fracturing fluid, preferably from 0.10 to
0.2% w/v of the fracturing fluid, and most preferably 0.12% w/v of the fracturing
20 fluid. The stability of gelling agent at higher temperature (above 90 0C) is limited by
factors such as pH, mechanical degradation, and oxidants.
[00024] Water softener is used to form a stable and soluble complex structure.
The water softener used in the present disclosure is selected from the group
consisting of inorganic salts of amino polycarboxylic acid, polyphosphates,
25 polyacrylates, salts of diethylenetriaminepenta(methylene-phosphonic acid), salts of
nitrilotrimethylenephosphonic acid, salts of ethylenediaminehydroxydiphosphonic
acid, salts of ethylenediaminetetramethylenephosphonic acid and mixtures thereof.
The water softener is present in the fracturing fluid in an amount in the range of from
7
0.1 to 2% w/v of the fracturing fluid, preferably from 0.3 to 1% w/v of the fracturing
fluid, and most preferably 0.5% w/v of the fracturing fluid.
[00025] pH buffering agents are used to provide the desirable pH profile (pH ≥
9.5). The low and the high pH buffering agent are used in the present disclosure for
proper hydration of the polymer. The high pH buffering agent used in the presen5 t
disclosure is selected from the group consisting of soda ash, sodium hydroxide,
potassium hydroxide, sodium carbonate, potassium carbonate, sodium bicarbonate,
potassium bicarbonate, sodium diacetate, potassium diacetate, monosodium
phosphate, monopotassium phosphate, and mixtures thereof. Preferred mixture of
10 high pH buffering agent used in the present disclosure is sodium carbonate and
sodium hydroxide in the ratio of 25:75 to 75:25. The high pH buffering agent is
present in the fracturing fluid in an amount in the range of from 0.5 to 1.5% w/v of
the fracturing fluid, preferably 1% w/v of the fracturing fluid. The low pH buffering
agent used in the present disclosure is selected from the group consisting of acetic
15 acid, hydrochloric acid, sulphonic acid, muriatic acid and mixtures thereof. The low
pH buffering agent is present in the fracturing fluid in the range of from 0.1 to 0.3%
v/v of the fracturing fluid, preferably from 0.1 to 0.15% v/v of the fracturing fluid.
[00026] The gelling agent used in the present disclosure is selected from the group
consisting of guar gum, hydroxypropyl guar, carboxymethyl hydroxypropyl guar,
20 carboxymethyl guar, carboxymethyl cellulose, carboxymethyl hydroxyethyl
cellulose, and mixtures thereof. The gelling agent is present in the fracturing fluid in
an amount in the range of from 0.2 to 1% w/v of the fracturing fluid, and preferably
from 0.6 to 0.7% w/v of the fracturing fluid. The gelling agent is used to get the
viscosity of the fracturing fluid in the range of 30-50 cP.
25 [00027] The non emulsifier used in the present disclosure is selected from the
group of nonionic surfactants. Most of the compounds in this classification are
esters, ethers and ether-esters. The lipophilic group may be derived from natural oils
and fats, petroleum oils or synthesized hydrocarbons. The hydrophilic group is
8
usually a polyhydric alcohol or an alkylated oxide polymer. The preferred non
emulsifier used in the present disclosure is selected from castor oil condensates. The
non emulsifier is present in the fracturing fluid in an amount in the range of from 0.1
to 1% v/v of the fracturing fluid, preferably from 0.3 to 0.7% v/v of the fracturing
fluid, and most preferably 0.5% v/v of the fracturing fluid. The non emulsifier 5 sifier will
water wet the formation, easily mixed with the fracturing fluid and prevent the
formation of emulsions. In water wet condition, the hydrophilic group of the non
emulsifier molecule forms a protective coating on the surface of the matrix thereby
allowing the hydrocarbons to flow easily through the matrix.
10 [00028] The surfactant used in the present disclosure is selected from nonionic
surfactants. Nonionic surfactants have no charge at all in the hydrophilic group and a
long chain organic lipophilic group. The water soluble group is a polymer made from
either ethylene oxide or propylene oxide. Other types include alkanol amine
condensates and amine oxides. The surfactant is present in the fracturing fluid in an
15 amount in the range of from 0.1 to 1% v/v of the fracturing fluid, preferably from 0.3
to 0.7% v/v of the fracturing fluid, and most preferably 0.5% v/v of the fracturing
fluid. The surfactant is used to break undesirable emulsions, reduce surface and/or
interfacial tension, alter wettability, speed cleanup, disperse additives and prevent
sludge formation.
20 [00029] The gel breaker used in the present disclosure is selected from the group
consisting of peroxydisulphate salts of ammonium, potassium and sodium. The most
preferred gel breaker used in the present disclosure is ammonium salts of
peroxidisulphate for use in wells having bottom hole temperature in the range of
60oC to 110oC. The gel breaker is present in the fracturing fluid in an amount in the
25 range of from 0.001 to 0.1% w/v of the fracturing fluid, preferably from 0.003 to
0.06% w/v of the fracturing fluid, and most preferably from 0.005 to 0.04% w/v of
the fracturing fluid. Gel breakers are used to reduce the viscosity of the fluid
intermingled with the proppant. Gel breakers reduce viscosity by cleaving the
9
polymer into small molecular weight fragments. For wells having bottom hole
temperature below 60oC, the most preferred breaker used in the present disclosure is
selected from ammonium salt of peroxidisulphate and amino alcohol. The preferred
range for use in wells having bottom hole temperature ≤ 60oC is 0.01 to 0.06 percent
of each by weight/volume. The most preferred 5 value is about 0.02 to 0.04 percent of
each by weight/volume of the fracturing fluid.
[00030] The cross linker used in the present disclosure is selected from the group
consisting of borate, Ti(IV), Zr(IV), Al(III). The preferred cross-linker used in the
present disclosure is borate. The borate source includes boric acid, sodium borate
10 hydrate, calcium borate salts. The cross-linker is carefully optimized to obtain the
desired performance such as rheology, proppant transport, thermal stability, crosslinking
rate, and cleanup. The borate compounds and transition metal complexes
react with guar and hydroxypropyl guar through cis-OH pairs on the galactose side
chains to form a complex which can further react with other polymer strands to form
15 a cross-linked network. A species is created with two times the molecular weight of
the polymer alone. Because each polymer chain contains many cis-OH groups, the
polymer can be cross-linked at more than one site. Network with a very high
molecular weight develop, especially under static conditions, resulting in highly
viscous solution. The cross linker is present in the fracturing fluid in an amount in
20 the range of from 0.017 to 0.042% w/v of the fracturing fluid, preferably from 0.022
to 0.033% w/v of the fracturing fluid, and most preferably 0.025% w/v of the
fracturing fluid.
[00031] The present disclosure relates to a fracturing fluid comprising: 95% (v/v)
of sea water; 0.03% (v/v) of biocide; 2% (w/v) of clay hydration suppressant; 0.12%
25 (w/v) of gel stabilizing agent; 0.5% (w/v) of water softener; 0.04 to 0.08% (v/v) of
low pH buffering agent; 0.7 to 0.9% (w/v) of high pH buffering agent; 0.6 to 0.7%
(w/v) of gelling agent; 0.5%(v/v) of non emulsifier; 0.5% (v/v) of surfactant; 0.005
10
to 0.04% (w/v) of gel breaker; 0.04% (w/v) of low temperature gel breaker; and
0.025% (w/v) of cross linker.
[00032] The present disclosure relates to a method of producing the fracturing
fluid, the process comprising: mixing sea water with biocide; clay hydration
suppressant; gel stabilizing agent; water softener; and gelling agent to form a mi5 x
water; mixing the mix water with high pH buffering agent to form a pH~8 mix
water; adding slowly gelling agent and low pH buffering agent to the pH~8 mix
water to form a pH≤7 mix water; hydrating the pH≤7 mix water with non emulsifier;
and surfactant to form a hydrated base gel of pH≤7; adding high pH buffering agent
10 and gel breaker to the hydrated base gel of pH≤7 to form a base gel; mixing cross
linker solution to the base gel with or without proppant to form a fracturing fluid.
[00033] The present disclosure describes a method of producing a fracturing fluid
for fracturing of subterranean formation, the process comprising: mixing 88 to 97%
(v/v) of sea water; with 0.01 to 0.1% (v/v) of biocide; 1 to 5 % (w/v) of clay
15 hydration suppressant; 0.08 to 0.4% (w/v) of gel stabilizing agent; 0.1 to 2% (w/v) of
water softener; and 0.2 to 1% (w/v) of gelling agent to form a mix water; mixing the
mix water with 0.5 to 1.5% (w/v) of high pH buffering agent to form a pH~8 mix
water; adding slowly 0.2 to 1% (w/v) of gelling agent and 0.1 to 0.3% (v/v) of low
pH buffering agent to the pH~8 mix water to form a pH≤7 mix water; hydrating the
20 pH≤7 mix water with 0.1 to 1% (v/v) of non emulsifier; and 0.1 to 1% (v/v) of
surfactant to form a hydrated base gel of pH≤7; adding 0.1 to 0.03% (w/v) of high
pH buffering agent and 0.003 to 0.06% (w/v) of gel breaker to the hydrated base gel
of pH≤7 to form a base gel; mixing 0.017 to 0.042% (w/v) of cross linker solution to
the base gel with or without proppant to form a fracturing fluid. The present
25 disclosure further discloses a method of producing a fracturing fluid for fracturing of
subterranean formation, the process comprising: mixing 88 to 97% (v/v) of sea
water; with 0.01 to 0.1% (v/v) of biocide; 1 to 5 % (w/v) of clay hydration
suppressant; 0.08 to 0.4% (w/v) of gel stabilizing agent; 0.1 to 2% (w/v) of water
11
softener; and 0.2 to 1% (w/v) of gelling agent to form a mix water; mixing the mix
water with 0.5 to 1.5% (w/v) of high pH buffering agent to form a pH~8 mix water;
adding slowly 0.2 to 1% (w/v) of gelling agent and 0.1 to 0.3% (v/v) of low pH
buffering agent to the pH~8 mix water to form a pH≤7 mix water; hydrating the
pH≤7 mix water with 0.1 to 1% (v/v) of non emulsifier; 5 ; and 0.1 to 1% (v/v) of
surfactant to form a hydrated base gel of pH≤7; adding 0.1 to 0.03% (w/v) of high
pH buffering agent and 0.003 to 0.06% (w/v) of gel breaker to the hydrated base gel
to form a base gel; mixing 0.017 to 0.042% (w/v) of cross linker solution to the base
gel with or without proppant to form a fracturing fluid; and contacting a subterranean
10 formation with the fracturing fluid for fracturing of subterranean formation, wherein
the subterranean formation has a temperature in the range of 60 ○C to 110 ○C.
[00034] The cross linker solution used in the present disclosure is prepared in a
separate tank by mixing a suitable cross linker capable of furnishing borate ions in
solution.
15 [00035] In the present disclosure, mixing of sea water with other additives is done
through batch mixing process which involves addition of different chemicals in a
single tank. So, water softeners are selected in such a way that the chemicals do not
react with each other.
[00036] The method used in the present disclosure has a single aqueous gelation
20 solution which is formulated by batch mixing sea water, a water softener whose
molecular structure can envelop and hold a certain type of ion/ions in a stable and
soluble complex and gelling agent Gd-II with other additives. The compatibility of
the water softener with other chemical additives/formation fluid is tested.
[00037] The present disclosure further discloses a system for fracturing Mumbai
25 off-shore oil and gas wells. Off-shore stimulation vessel with fracturing set up is
being used for fracturing Mumbai off-shore oil & gas wells with facility for batch
mixing of chemicals. The aqueous based fracturing fluid of the present disclosure is
a base fluid, which is typically sea water, a hydratable polymer, other additives and a
12
cross linker. These fluids also typically include buffers to adjust the pH of the base
fluid in order to control the rate of subsequent cross-linking. The present disclosure
concerns the use of water softener in fracturing fluid to make it compatible with sea
water by “softening” or preventing the divalent cations in sea water from hindering
complexation of the polymer that improved fluid stability 5 can be provided over a
broad temperature range from about 60oC to at least 110oC. Various methods can be
used to “soften” the sea water these includes ion exchange, precipitation, and
addition of chelating or sequestering agents. The preferred method involves the use
of chelating or sequestering agents. The advantages of using chelating or
10 sequestering agents in borate cross-linked fluids are: these agents provide additional
buffer capacity and provide scale inhibition in the proppant pack formation and the
pipe.
[00038] Preparation of fracturing fluid depends on the quality of water used for its
preparation. Optimization of doses of the constituent chemicals is essential for
15 successful execution of fracturing operations. Sea water from Mumbai Off-shore was
used in the present disclosure. The sea water contains magnesium ions, calcium ions,
and sodium ions as major components and typically has a pH around 8. Other ionic
species may be present in minor amounts. The respective amounts of ions in the sea
water typically range from about 2500 to 6000 ppm magnesium ions, about 1000 to
20 2000 ppm calcium ions and about 18000 to 21000 ppm chloride ions. The calculated
total dissolved solids being in the range of 51000 to 56000 ppm.
[00039] Stability of the fracturing fluid plays a vital role in the fracturing
operation. Good quality fracturing fluid can only be prepared when the base gel
viscosity of about 35 to 45 cPs is achieved. Since, the present disclosure involves
25 batch mixing of chemicals, optimization of hydration time of the polymer in given
sea water, containing adequate water softner, is done in order to achieve the required
base gel viscosity.
13
[00040] Cross-linking dosage was optimised to ensure the sufficient rheological
strength of the fracturing fluid to carry the proppant deep into the targeted formation
zone.
[00041] As the fracturing fluid is water based, application of non emulsifier is
needed to prevent any emulsion formation. Demulsification studies were carried 5 out
using non-ionic non-emulsifiers with formation water, sea water, and untreated crude
oil samples of L-II, L-III, Basement and basal clastics of Mumbai off-shore region.
Fracturing fluid when pumped into the formation comes in contact with formation
fluid (formation water, oil/gas). It should not form any emulsion with these fluids as
10 it will adversely affect the post fracturing flow of fluids.
[00042] Fracturing fluid should be stable enough at the reservoir conditions for
the stipulated time. Study of the gel stability with time at simulated reservoir
conditions is necessary to optimize the doses of the chemical constituents.
[00043] Broken fracturing fluid should flow back after the stipulated time.
15 Optimization of breaker dosage was carried out for smooth flow back.
[00044] Reactivity of the fracturing fluid constituents with the carbonate
(limestone) was seen to evaluate any precipitation.
[00045] Studies were conducted at temperatures 60 to 110oC. Preferred
temperature for fracturing wells having bottom hole temperatures from 75 to 100oC.
20 [00046] Further, the present disclosure relates to a system for fracturing off shore
oil and gas wells using hard mix water.
[00047] In an embodiment, the present disclosure provides a method of producing
a fracturing fluid for fracturing of subterranean formation, the process comprising:
mixing 95% (v/v) of sea water; with 0.03% (v/v) of biocide; 2% (w/v) of clay
25 hydration suppressant; 0.12% (w/v) of gel stabilizing agent; and 0.5% (w/v) of water
softener to form a mix water; mixing the mix water with 0.65% (w/v) of high pH
buffering agent to form a pH~8 mix water; adding slowly 0.6 to 0.7% (w/v) of
gelling agent and 0.02 to 0.06% (v/v) of low pH buffering agent to the pH~8 mix
14
water to form a pH≤7 mix water; hydrating the pH≤7 mix water with 0.5% (v/v) of
non emulsifier; and 0.5% (v/v) of surfactant to form a hydrated base gel of pH≤7;
adding 0.1 to 0.3% (w/v) of high buffering agent and 0.01 to 0.04% (w/v) of gel
breaker to the hydrated base gel of pH≤7 to form a base gel of pH≥9.5; mixing
0.025% 5 (w/v) of cross linker solution to the base gel with or without proppant to
form a fracturing fluid; and contacting a subterranean formation with the fracturing
fluid for fracturing of subterranean formation, wherein the subterranean formation
has a temperature in the ratio of 60 ○C to 110 ○C.
[00048] The process steps of the present invention are described in the
10 embodiments. Selected embodiments have been described by way of examples. They
are only illustrative in nature and should not be construed as limiting the scope of the
invention in any manner. It is obvious for a person skilled in the art that changes can
be made without deviating from the scope of the invention as defined in the claims.
[00049] The present disclosure describes a method for stimulating a subterranean
15 well using a sea water-based fracturing fluid which is complexed or cross-linked
with commonly available agents.
[00050] The present disclosure further describes a method which does not greatly
increase the cost of the fracturing treatment and also provides a stable fracturing
fluid having adequate proppant transport capabilities and viscosity to provide
20 adequate fracture geometries over a broad temperature range.
EXAMPLES
[00051] The disclosure will now be illustrated with working examples, which is
intended to illustrate the working of disclosure and not intended to take restrictively
to imply any limitations on the scope of the present disclosure.
25 Example 1: Composition of the fluid formulation:
[00052] The composition of the fluid formulation comprises the following
ingredients:
 88 to 97% (v/v) of sea water;
15
 0.01 to 0.05% (v/v) of biocide;
 1 to 3 % (w/v) of clay hydration suppressant;
 0.1 to 0.2% (w/v) of gel stabilizing agent;
 0.3 to 1% (w/v) of water softener;
 5 0.1 to 0.3% (v/v) of low pH buffering agent;
 0.5 to 1.5% (w/v) of high pH buffering agent;
 0.2 to 1% (w/v) of gelling agent;
 0.3 to 0.7% (v/v) of non emulsifier;
 0.3 to 0.7% (v/v) of surfactant;
10  0.003 to 0.06% (w/v) of gel breaker; and
 0.022 to 0.033% (w/v) of cross linker.
Example 2: Composition of the fluid formulation:
[00053] The composition of the fracturing fluid prepared using sea water as a base
fluid comprises the following ingredients shown in Table 1, depending on bottom
15 hole temperature of the candidate well:
Table 1:
Sl
No
Additives Fracturing fluid formulation for
wells having bottom hole temp.
60±2 0C 90±2 0C 110±2 0C
1 Biocide (% v/v) 0.03 0.03 0.03
2 Clay hydration suppressant (%
w/v)
2.0 2.0 2.0
3. Gel stabilizing agent (% w/v) Nil 0.12 0.12
4. Water softener (% w/v) 0.5 0.5 0.5
5. Low pH buffering agent (% v/v) 0.10 – 0.15 0.10 –
0.15
0.10 – 0.15
6. High pH buffering agent(% w/v) 1.0 1.0 1.0
16
7. Gelling Agent (%w/v) 0.6 0.6 0.7
8. Non emulsifier (% v/v) 0.5 0.5 0.5
9. Surfactant (% v/v) 0.5 0.5 0.5
10 Gel Breaker (% w/v) 0.04 0.03 0.02
11 Low Temp. breaker(% v/v) 0.04 Nil Nil
12 Cross linker (%w/v) 0.025 0.025 0.025
Example 3: Method for producing a fracturing fluid for fracturing of subterranean
formation.
[00054] The mixing process in the present disclosure involves mixing of 95%
(v/v) sea water (containing about 6500 ppm total hardness, 5 , about 20600 ppm
chloride content and about 56000 ppm of total dissolved solids) with 0.03% (v/v) of
biocide, 2% (w/v) of clay hydration suppressant, 0.12% (w/v) of gel stabilizing
agent (optional depending upon the bottom hole temperature of the well concerned),
0.001-0.04% (w/v) of gel breaker (optional depending upon the bottom hole
10 temperature of the well concerned) and 0.50% (w/v) of water softener to form a mix
water. The pH of the mix water is then raised to pH~8 by mixing about 0.60% (w/v)
of high pH buffering agent. The pH~8 mix water is placed in a blender and while in
agitated state the required quantity, 0.60-0.70% (w/v), of gelling agent is added. At
this stage very slow addition of gelling agent to the mix water is highly desirable.
15 After the completion of the addition of the required amount of gelling agent to the
mix water, the pH of the fluid is adjusted to a pH≤7 by adding about 0.02-0.06%
(v/v) of low pH buffering agent. While in an agitated state, the polymer is then
allowed to hydrate for about 30 minutes. During this hydration period 0.5% (v/v) of
non emulsifier and 0.5% (v/v) of surfactant is added to form a hydrated base gel of
20 pH≤7. The pH of this hydrated base gel is raised to a pH≥9.5 by adding 0.10-0.3%
(w/v) of high pH buffering agent. 0.01–0.04% (v/v) of low temperature breaker
(optional depending upon the bottom hole temperature of the well concerned) is
17
added at this stage. This high pH hydrated base gel (viscosity 35-40 cPs) is stored in
a fracturing fluid tank. On the fly mixing of 0.025% (w/v) cross linker solution to the
high pH hydrated base gel with or without proppant produces viscoelastic crosslinked
fracturing fluid; and contacting a subterranean formation with the fracturing
fluid for fracturing of subterranean formation, wherein the 5 subterranean formation
has a temperature in the range of 60oC to 110oC.
Example 4: Water Quality studies:
[00055] The water samples received from MH Asset were analyzed to check its
suitability for the preparation of fracturing fluid. The results are tabulated in Table-
10 2:
Table 2: Properties of water samples
18
[00056] From Table 2, it is confirmed that sea water contains multivalent ions
such as calcium and magnesium ions which form insoluble precipitates at a pH ≥ 9.5
(required pH for good borate cross-linking for wells having bottom hole temperature
up to 120 oC). The presence of solid precipitates reduces 5 the proppant pack
conductivity, and ultimately the productivity of the fracturing operations.
Furthermore, elevating the pH of the fracturing fluid to a pH greater than about 9.5 is
difficult due to the formation of magnesium hydroxide. Hydroxyl ions needed to
elevate the pH of sea water are instead consumed in the formation of magnesium
10 hydroxide. This reaction proceeds very slowly causing the pH change to be timedelayed
and difficult to adjust.
ANALYSIS REPORT OF PRODUCED WATER (ICP) AND SEAWATER
(ICP)
SL.
NO.
PARAMETERS UNIT PRODUCED
WATER (ICP)
SEA WATER
(ICP)
1 pH - 6.9 8.1
2 Conductivity μmhos/cm 66400 72700
3 Total Hardness mg/l 2500 6500
4 Calcium Hardness mg/l 1500 1000
5 Magnesium Hardness mg/l 1000 5500
6 Chloride mg/l 18460 20590
7 Alkalinity mg/l 850 150
8 Total Dissolved Solids mg/l(calculated) 51128 55979
9 Total Suspended Solids mg/l 529 1.8
10 Turbidity NTU 15.5 0.2
11 COD mg/l 1040 32
12 BOD (3 days, 27 oC) mg/l 278 2
19
[00057] In addressing the problems associated with precipitate formation in high
temperature sea water based fracturing fluids, prior art methods suggests the removal
of solid precipitates by filtration. The present disclosure relates to fracturing fluid
comprising sea water and water softener, where no precipitation is observed and
therefore no pre-filtration of precipitations 5 tations is required.
[00058] Table 3: Effect of increasing pH of sea water with and without the
addition of 0.5% (w/v) of water softener.
[00059] It is evident from the table 3 that heavy precipitation occurs when water
10 softener chemical was not added to the sea water. However, when water softener was
added to sea water no precipitation was observed.
Example 5: Studies for determining the quantity of gelling agent required and
stability of plain gel.
[00060] Laboratory studies were carried out for determining the quantity of guar
15 based gelling agent Gd.-II (GA-II), required for the preparation of linear gel of
viscosity 40 cps at 300 rpm (511s-1 shear rate) measured using multispeed
Rheometer-NL Baroid make. Results are shown in Table 4(a).
Table 4(a): % of Gelling Agent (guar based) & the measured viscosity at 300 rpm
(*0.5% water softener chemical + 2% KCl in sea water)
pH Sea water without water softener
chemical
Sea water with water softener
chemical
≥ 9.5
Heavy precipitation observed
No precipitation observed
% age of GA-II* Observed Viscosity at 300 rpm
0.60 33
0.65 38
0.70 42
20
[00061] It is evident from the above table that 0.60 – 0.70 % of gelling agent is
sufficient for attaining the required base gel viscosity ~ 30-40 cps in sea water
containing 0.5% water softener and 2% KCl.
[00062] The linear gel having pH adjusted to ≥ 5 9.5 (by adding Soda ash) was kept
at 40±2oC for 48 hours and viscosity & pH were measured. The results are shown in
Table 4(b).
Table 4(b): Linear gel viscosity (300 rpm) & pH after 48 hrs at 40±2oC
(*0.5% Water softener + 2% KCl in sea water)
10 [00063] It is evident from the table 4(b), the base gel is stable at 40±2 oC for at
least 48 hrs and further hydration of the gel indicates the absence of microbial
degradation of the polymer. Furthermore, constant pH even after 48 hrs. is indicative
of the fact that no precipitation of magnesium occurs.
Example 6: Compatibility test of water softener chemical with other fracturing fluid
15 additives in given sea water sample:
[00064] Compatibility studies of water softener chemical in given sea water with
other additives like, KCl, biocide, soda ash, non emulisifiers, surfactant, acetic acid,
cross linkers and breakers were carried. Results are shown in Table 5.
Table 5: Compatibility of sea water solution of water softener with other additives
20 and formation water samples.
Sl. No. Additives Concentration
range (%) w/v
Formation of ppt. in
sea water solution of
0.5% water softener
Concentration of
GA-II*(%)
Observed viscosity and pH
Initial After 48 hrs.
viscosity pH viscosity pH
0.70 42 9.6 43 9.6
21
1 Clay hydration Suppressant
(Potassium chloride)
1 - 3 Negative
2 Buffering Agent
(Soda ash)
0.1 - 1.0 Negative
3 Acetic acid 0.1 – 0.3 Negative
4 Gel Stabiliser
(Sodium thiosulphate)
0.1 – 0.2 Negative
5 Low temperature activator /
gel breaker (Triethanol
amine)
0.01 – 0.05 Negative
6 Non Emulsifier for KLLNGM
field
0.4 – 0.6 Negative
7 Non Emulsifier for Wasna
field
0.4 – 0.6 Negative
8 Non Emulsifier for Sobhasan
field
0.4 – 0.6 Negative
9 Non Ionic/Anionic-Surfactant 0.5 – 0.7 Negative
10 Gel Breaker
(Ammonium persulphate)
0.001 – 0.1 Negative
11 High Temp Gel Stabiliser
(Sodium gluconate)
0.05 – 0.1 Negative
12 High Temp Gel Breaker
(Sodium bromate)
0.02 – 0.1 Negative
13 Cross linker
(Borax)
0.02 – 0.1 Negative
14 Formation water from SM#5 100 – 500 (v/v) Negative
15 Formation water from L-II 100 – 500 (v/v) Negative
16 Formation water from L-III 100 – 500 (v/v) Negative
22
[00065] Compatibility studies are undertaken where multiple additives are being
added to the same system. It is observed that addition of multiple additives do not
interfere with each other during or post hydraulic fracturing treatment. KLL-NGM
denotes for Kalol and Nawagam fields of Ahmedabad 5 d asset of ONGC. SM#5 is an
oil & gas well in M-BHS field of Mumbai offshore. L-II denotes a producing layer in
limestone reservoir of Mumbai Offshore L-III denotes a producing layer in limestone
reservoir of Mumbai Offshore.
Example 7: Optimization of Cross Linker dosage:
10 [00066] Borax at pH ≥ 9.5 is being used as Cross Linker. Results are shown in
Table 6.
Table 6: Dose optimization studies of Cross Linker
% of Cross Linker
used
Quality of Cross Linked gel prepared in sea water*
Initial After 4 Hrs**.
0.03 Good Good
0.04 Very good Very good
0.05 Good Good
0.06 Syneresis occurs Syneresis occurs
(*0.5% water softener + 2% KCl in sea water) (** without breaker)
15 [00067] From the Table 6 it is evident that 0.04% of cross linker is sufficient for
getting stable very good cross linked gel which indicates that the borate equilibrium
provides proper borate ion concentration in the presence of 0.5% water softener,
hence pH is completely balanced.
Example 8: Optimization of breaker dosage:
20 [00068] Gel breaking or reduction in the viscosity of cross linked fracturing fluid
after pumping is important for obtaining high fracture conductivity. Borate gel
viscosity is greatly reduced when fluid pH drops below the value necessary to sustain
23
a borate-ion equilibrium concentration high enough for crosslinking. Complete
breaking also requires a reduction of polymer molecular weight. Oxidative gel
breakers were tried in this study. They are sensitive to salinity and temperature but
less sensitive to pH. Ammonium per sulphate (APS) provides controlled breaking
between 65 to 110±2oC. Below 60±2oC, a chemical activator (TEA) is required 5 d to
enhance the low temperature oxidizing breaking of APS.
[00069] Experiments were carried out at 60±2oC, 70±2oC and 80±2oC to observe
the breaking time of the cross linked gel (prepared in sea water) with APS. Results
are shown in Table 7(i). Performance of APS at higher temperatures is shown in
10 Table 7(ii).
TABLE 7(i): Performance of APS at different temperatures with and without
Chemical activator.
% of
APS
Observed breaking time of X-linked gel prepared in sea water*
At 80±2oC At 70±2oC At 60±2oC
With TEA (0.04%) +
APS
0.01 Broken after 3.0 hrs. Broken after 3.5 hrs. Broken after 5.5 hrs.
0.02 Broken after 2.0 hrs. Broken after 3.0 hrs. Broken after 4.0 hrs.
0.03 Broken after 1.5 hrs. Broken after 2.0 hrs. Broken after 2.5 hrs.
0.04 Broken after 1 hrs. Broken after 1.5 hrs. Broken after 1.5 hrs.
(*0.5% water softener + 2% KCl in sea water)
15 TABLE 7(ii): Performance of APS at higher temperatures:
%age
of
APS
Observed breaking time of X-linked gel prepared in sea water*
At 90±2oC At 100±2oC with
0.12% Sodium
At 110±2oC with
0.12% Sodium
24
thiosulphate thiosulphate
0.001 Broken after 2.0 hrs. Broken after 3.0 hrs. Broken after 2.5 hrs.
0.005 Broken after 1.5 hrs. Broken after 2.5 hrs. Broken after 2.0 hrs.
0.01 Broken after 1.0 hrs. Broken after 1.5 hrs. Broken after 1.5 hrs.
0.02 Broken after 0.5 hrs. Broken after 1.0 hrs. Broken after 0.5 hrs.
(*0.5% water softener + 2% KCl in sea water)
[00070] Oxidative gel breakers were tried in the present disclosure. They are
sensitive to salinity and temperature but less sensitive to pH. Ammonium per
sulphate (APS) provides controlled breaking between 60 to 110±2oC. At 60±2oC, a
chemical activator (TEA) is required to enhance the low temperature oxidizin5 g
breaking of APS.
[00071] Because APS is not encapsulated, the soluble breaker can be carried with
the fluid entering the formation matrix; however, full breaking action begins after a
substantial induction time as shown in table 7(i) and 7(ii). The fluid maintains high
10 viscosity, which allows fracture geometry generation and proppant transport. After
transport, the viscosity is reduced, after breaking of gel, for flow back.
[00072] It is evident from the above table that 0.02 to 0.03% APS alone is
sufficient for effective breaking of the X-linked gel at 70 & 80±2oC. At 60±2oC,
0.04% each of APS and TEA is required for the breaking. At higher temperatures
15 0.005 – 0.01% APS, depending on BHT of the well concerned, is sufficient to break
the cross linked gel.
Example 9: Gel Breaking
[00073] Because APS is not encapsulated, the soluble breaker can be carried with
the fluid entering the formation matrix; however, full breaking action begins after a
20 substantial induction time as shown in Figure 1. The fluid maintains high viscosity,
which allows fracture geometry generation and proppant transport. After transport,
the viscosity is reduced for flow back.
Example 10: Scaling Tendencies
25
[00074] The formation of inorganic, sparingly soluble salts from aqueous brines
during oil and gas production, is known as ‘scale’ and is one of the major flow
assurance problems. Scale forms and deposits under supersaturated conditions,
wherever the mixing of the incompatible types of water; formation water from the
bottom hole and the injected sea water, takes place. The deposited scale adheres 5 s on
the surfaces of the producing well tubing and on parts of water handling equipment,
where it builds up in time and leads to problems in reservoirs, pumps, valves and top
side facilities. The rapid increase of the mineral deposits leads to inevitable damage
of the equipment parts. As a consequence, suspension of oil operations is necessary
10 for the recovery or replacement of damaged parts. In the oil field these interruptions
are accompanied by extremely high costs. Sea water and formation brines contain
multiple ions that can form insoluble precipitates. Particularly, magnesium is a cation
that can form an insoluble precipitate in the pH range of borate crosslinking. Sea
water containing 0.5% water softener and 2% KCl does not pose a scaling problem.
15 Moreover, once the treatment ends and the fracturing fluid starts to equilibrate with
low- pH formation water, the pH of the spent fluid will drop, as shown in Figure 2
allowing the magnesium, if at all not sequestered, to re-dissolve. A pH below 9.0 is
sufficient to solubilize Mg(OH)2 particles. However, sea water contains significant
amount of sulphate ions that precipitate with strontium or barium upon contact with
20 formation waters. Sea water containing 0.5% water softener chemical and 2% KCl
when mixed with the formation water collected from #L-II, #L-III and
Basement/Basal clastics, it neither cause calcium precipitation, nor strontium /
barium precipitated as sulphates. Analytical tests of the broken borate crosslinked
fluid, prepared in sea water containing 0.5% water softener and 2% KCl, indicated
25 complete control of sulphate scales.
Example 11: Demulsification test with un-treated crude oil samples:
[00075] Plain gel of viscosity 50~55 cps was prepared by mixing Gelling agent
Gd.–II in 2% KCl and 0.5% water softener solution in sea water. This gel was mixed
26
with crude oil samples in two different proportions: (i) 1:1 (gel : oil ) and (ii) 1:3 (gel
: oil ) in a Hamilton beach mixer operated at 18000 RPM for 30 seconds. 0.5% (v/v)
of non emulsifier for water base fracturing fluid was also added to these emulsions in
the mixer and finally the emulsions were kept at 90±2oC for 12 hrs. The same set of
experiments 5 nts was also carried out with 0.5% (v/v) of surfactant in place of non
emulsifier. Sludge formation after demulsification at the interface of the crude oil
and broken gel was also studied. Results are shown in Table 8.
Table 8: Demulsification & Sludge formation Test:
Source of
untreated
Crude oil
sample
Non
emulsifier
/surfactant
sample
Gel :
Crude
oil ratio
Demulsification Sludge formation
Reqd.
(%)
Obs.
(%)
Reqd.
(%)
Obs.
(%)
SM # 5 NE for
KLL-NGM
1 : 1 100 100 Nil Nil
SM # 5 NE for
KLL-NGM
1 : 3 100 100 Nil Nil
SM # 5 NE for
Wasna
1 : 1 100 100 Nil Nil
SM # 5 NE for
Wasna
1 : 3 100 100 Nil Nil
SM # 5 NE for SBN 1 : 1 100 100 Nil Nil
SM # 5 NE for SBN 1 : 3 100 100 Nil Nil
SM # 5 NISurfactant
1 : 1 100 100 Nil Nil
SM # 5 NISurfactant
1 : 3 100 100 Nil Nil
L-II NE for
KLL-NGM
1 : 1 100 100 Nil Nil
27
L-II NE for
KLL-NGM
1 : 3 100 100 Nil Nil
L-II NE for
Wasna
1 : 1 100 100 Nil Nil
L-II NE for
Wasna
1 : 3 100 100 Nil Nil
L-II NE for SBN 1 : 1 100 100 Nil Nil
L-II NE for SBN 1 : 3 100 100 Nil Nil
L-II NISurfactant
1 : 1 100 100 Nil Nil
L-II NISurfactant
1 : 3 100 100 Nil Nil
L-III NE for
KLL-NGM
1 : 1 100 100 Nil Nil
L-III NE for
KLL-NGM
1 : 3 100 100 Nil Nil
L-III NE for
Wasna
1 : 1 100 100 Nil Nil
L-III NE for
Wasna
1 : 3 100 100 Nil Nil
L-III NE for SBN 1 : 1 100 100 Nil Nil
L-III NE for SBN 1 : 3 100 100 Nil Nil
L-III NISurfactant
1 : 1 100 100 Nil Nil
L-III NISurfactant
1 : 3 100 100 Nil Nil
28
[00076] As the fracturing fluid is water based, application of non emulsifier is
needed to prevent any emulsion formation inside the formation. Since,
demulsification test is the conformity test for non-emulsification, demulsification
studies must be carried out with formation fluid, sea water to be used, untreated
crude oil samples of the concerned fields. Table 8 depicts the results of the carri5 ed
demulsification tests. If demulsification is less than 100%, then there will be sludge
formation at the interface of the crude oil and broken gel.
[00077] Sea water contains more dissolved ions than fresh water. Sodium,
chloride, magnesium, sulfate and calcium are the most abundant dissolved ions in
10 sea water are which form insoluble precipitates at pH greater than or equal to 9.5.
The presence of solid precipitates reduces the proppant pack conductivity and
ultimately the productivity of the fracturing operations. Furthermore, elevating the
pH of the fracturing fluid to pH ≥ 9.5 is difficult due to the formation of magnesium
hydroxide. Hydroxyl ions needed to elevate the pH of sea water are consumed in the
15 formation of magnesium hydroxide. This reaction proceeds very slowly causing the
pH change difficult to adjust. Also, high ionic strength affects the performance of the
fracturing fluid’s components and thereby both viscosity and strength of fracturing
fluid decreases.
[00078] To overcome the problem literature discloses use of metal carbonates for
20 the precipitation of the multivalent cations present in the sea water. Prior art methods
suggest the removal of solid precipitates in the sea water by filtration. However, the
proper disposal of magnesium hydroxide and other precipitates creates additional
operational costs as well as environmental challenges. The prior art methods
involves high cost of the fracturing treatment.
25 [00079] In the prior art, there is a problem of precipitation, at pH≥ 9.5. To
overcome the problem of precipitation, chemicals whose molecular structure can
envelop and hold precipitable ions in a stable and soluble complex is used in the
present disclosure. Divalent cations, such as hardness ions, form stable and soluble
29
complex structures with several types of water softeners. When held inside the
complex, the ions have a limited ability to react with other ions, clays or polymers.
ADVANTAGES
[00080] The previously described versions of the subject matter and its equivalent
thereof have many advantages, including those 5 e which are described below.
 Using sea water in offshore wells will save considerable time and cost
involved in transportation of huge volume of fresh water from the shore for
hydro fracturing operations.
 The fracturing fluid of the present disclosure containing sea water and water
10 softener do not produce any precipitation.
 The present composition is inexpensive and simple to prepare, using batch
mixing process.
 The fracturing fluid of the present disclosure is stable at temperatures in the
range of 60 to 110 oC and at a pH of about 9.5 or greater.
15  Used for fracturing offshore wells having temperature up to 110 ○C.
 The chemicals used in the fracturing fluid are indigenous chemicals.
[00081] Although the subject matter has been described in considerable detail
with reference to certain preferred embodiments thereof, other embodiments are
possible. As such, the spirit and scope of the appended claims should not be limited
20 to the description of the preferred embodiment contained therein.
30
I/We Claim:
1. A fracturing fluid comprising: sea water; biocide; clay hydration suppressant; gel
stabilizing agent; water softener; low pH buffering agent; high pH buffering
agent; gelling agent; non emulsifier; surfactant; gel breaker; and cross linker5 .
2. The fracturing fluid as claimed in claim 1, wherein the fracturing fluid comprises
of 88 to 97% (v/v) of sea water; 0.01 to 0.1% (v/v) of biocide; 1 to 5 % (w/v) of
clay hydration suppressant; 0.08 to 0.4% (w/v) of gel stabilizing agent; 0.1 to 2%
(w/v) of water softener; 0.1 to 0.3% (v/v) of low pH buffering agent; 0.5 to 1.5%
10 (w/v) of high pH buffering agent; 0.2 to 1% (w/v) of gelling agent; 0.1 to 1%
(v/v) of non emulsifier; 0.1 to 1% (v/v) of surfactant; 0.001 to 0.1% (w/v) of gel
breaker; and 0.017 to 0.042% (w/v) of cross linker.
3. The fracturing fluid as claimed in claim 1, wherein the fracturing fluid optionally
comprises of a low temperature breaker.
15 4. The fracturing fluid as claimed in claim 1, wherein the fracturing fluid comprises
of 88 to 96% (v/v) of sea water; 0.01 to 0.1% (v/v) of biocide; 1 to 5 % (w/v) of
clay hydration suppressant; 0.08 to 0.4% (w/v) of gel stabilizing agent; 0.1 to 2%
(w/v) of water softener; 0.1 to 0.3% (v/v) of low pH buffering agent; 0.5 to 1.5%
(w/v) of high pH buffering agent; 0.2 to 1% (w/v) of gelling agent; 0.1 to 1%
20 (v/v) of non emulsifier; 0.1 to 1% (v/v) of surfactant; 0.001 to 0.1% (w/v) of gel
breaker; 0.01 to 0.06% (v/v) of low temperature breaker; and 0.017 to 0.042%
(w/v) of cross linker.
5. The fracturing fluid as claimed in claim 1, wherein the biocide is selected from
the group consisting of formaldehyde, gluteraldehyde, chlorophenates,
25 quaternary amines, isothiazoline, 2-bromo-2-nitrilo, 3-propanedol, 2,2-dibromo-
3-nitrilopropionamide, 2- bromo-3-nitrilopropionamide, and mixtures thereof.
31
6. The fracturing fluid as claimed in claim 1, wherein the clay hydration
suppressant is selected from the group consisting of inorganic salts, preferably
KCl, NaCl, KBr, Al2Cl3 and mixtures thereof.
7. The fracturing fluid as claimed in claim 1, wherein the gel stabilizing agent is
selected from the group consisting of sodium thiosulphate, sodium 5 sulfite,
sodium erythorborate, methanol, thiourea and mixtures thereof.
8. The fracturing fluid as claimed in claim 1, wherein the water softener is selected
from the group consisting of inorganic salts of amino polycarboxylic acid,
polyphosphates, polyacrylates, salts of diethylenetriaminepenta(methylene10
phosphonic acid), salts of nitrilotrimethylenephosphonic acid, salts of
ethylenediaminehydroxydiphosphonic acid, salts of
ethylenediaminetetramethylenephosphonic acid and mixtures thereof.
9. The fracturing fluid as claimed in claim 1, wherein the low pH buffering agent is
selected from the group consisting of acetic acid, hydrochloric acid, sulphonic
15 acid, muriatic acid and mixtures thereof.
10. The fracturing fluid as claimed in claim 1, wherein the high pH buffering agent is
selected from the group consisting of soda ash, sodium hydroxide, potassium
hydroxide, sodium carbonate, potassium carbonate, sodium bicarbonate,
potassium bicarbonate, sodium diacetate, potassium diacetate, monosodium
20 phosphate, monopotassium phosphate, and mixtures thereof.
11. The fracturing fluid as claimed in claim 1, wherein the gelling agent is selected
from the group consisting of guar gum, hydroxypropyl guar, carboxymethyl
hydroxypropyl guar, carboxymethyl guar, carboxymethyl cellulose,
carboxymethyl hydroxyethyl cellulose, and mixtures thereof.
25 12. The fracturing fluid as claimed in claim 1, wherein the non emulsifier is selected
from the group of nonionic surfactants.
32
13. The fracturing fluid as claimed in claim 1, wherein the gel breaker is selected
from the group consisting of peroxydisulphate salts of ammonium, potassium and
sodium.
14. The fracturing fluid as claimed in claim 1, wherein the cross linker is selected
from the group consisting 5 ting of borate, Ti(IV), Zr(IV), Al(III).
15. A method of producing the fracturing fluid as claimed in claim 1, the process
comprising: mixing sea water with biocide; clay hydration suppressant; gel
stabilizing agent; water softener; and gelling agent to form a mix water; mixing
the mix water with high pH buffering agent to form a pH~8 mix water; adding
10 slowly gelling agent and low pH buffering agent to the pH~8 mix water to form a
pH≤7 mix water; hydrating the pH≤7 mix water with non emulsifier; and
surfactant to form a hydrated base gel of pH≤7; adding high pH buffering agent
and gel breaker to the hydrated base gel of pH≤7to form a base gel; mixing cross
linker solution to the base gel with or without proppant to form a fracturing fluid.
15 16. The method as claimed in claim 15, the process comprising: mixing 88 to 97%
(v/v) of sea water; with 0.01 to 0.1% (v/v) of biocide; 1 to 5 % (w/v) of clay
hydration suppressant; 0.08 to 0.4% (w/v) of gel stabilizing agent; 0.1 to 2%
(w/v) of water softener; and 0.2 to 1% (w/v) of gelling agent to form a mix water;
mixing the mix water with 0.5 to 1.5% (w/v) of high pH buffering agent to form
20 a pH~8 mix water; adding slowly 0.2 to 1% (w/v) of gelling agent and 0.1 to
0.3% (v/v) of low pH buffering agent to the pH~8 mix water to form a pH≤7 mix
water; hydrating the pH≤7 mix water with 0.1 to 1% (v/v) of non emulsifier; and
0.1 to 1% (v/v) of surfactant to form a hydrated base gel of pH≤7; adding 0.1 to
0.03% (w/v) of high buffering agent and 0.003 to 0.06% (w/v) of gel breaker to
25 the hydrated base gel of pH≤7to form a base gel; mixing 0.017 to 0.042% (w/v)
of cross linker solution to the base gel with or without proppant to form a
fracturing fluid.
33
17. A method of contacting a subterranean formation with the fracturing fluid as
claimed in claim 1 for fracturing of subterranean formation, wherein the
subterranean formation has a temperature in the range of 60○C to 110○C.