Note: Descriptions are shown in the official language in which they were submitted.
CA 02354789 2001-08-07
FRACTURING METHOD USING AQUEOUS OR ACID BASED FLUIDS
Field of the Invention
The present invention relates to the field of fracturing fluids, in
particular,
surfactant based fracturing fluids.
Background of the Invention
A fracturing fluid is a fluid that is pumped into a hydrocarbon-bearing
reservoir
in a geological formation under high pressure to open fractures in the
formation,
thereby to facilitate the flow of hydrocarbons from the formation. Fracturing
fluids are
preferably viscous, so as to be able to carry proppants into the fractures
that are
forced open in the formation.
Conventional fracturing fluids contain high molecular weight polysaccharides
based polymers, as gelling agents. These polymers are associated with build-up
of
filter cake on the fracture face. If the filter cake is not completely
removed, it will
impede flow of reservoir fluid and hence reduce the effectiveness of the
fracture.
Control and limiting of residual filter cake becomes extremely important when
dealing
with problematic formations. Alternative to the conventional polymeric system
is the
novel development of the present invention.
The present invention is ~~ non-polymeric visco-elastic system. The system is
based on surfactant chemistry. Although surfactant based systems have been
employed in gravel packing operations since the early 1980s (SPE 17168),
further
development and refinement of surfactant chemistry has yielded surfactant
based
fracturing fluids. Some of these techniques are discussed and revealed in
Canadian
Patent No. 1,298,697 and U.S. Patent No. 5,964,295.
The advantage of a surfactant based fracturing fluid over a polymeric gel
based fluid is that micelle formation in surfactant fluids is virtually
instantaneous, but
does not alter the actual chemical composition of the fluid. That is, once a
critical
concentration of surfactant molecules is reached, they will aggregate as
micelles,
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CA 02354789 2005-08-05
thereby increasing the viscosity of the fluid, but without changing the
chemical
composition. Therefore, no chemical initiator is required, and viscosity
increase
occurs uniformly throughout the fluid.
The key to the present invention therefore is the novel use of amphoteric
glycinate surfactant, as an additive. In acidic conditions, the glycinate
exhibits
cationic properties. When the glycinate is combined in proper ratio with
anionic salt
such as Sodium Xylene Sulfonate in a neutral to acidic environment of an
aqueous
stimulation fluid (water or acid) it is believed to form highly structured
three
dimensional micelles. The interference/interaction of the micelles imparts the
desired
viscoelastic properties to the stimulation fluid. The required cationic
activity of the
glycinate is ensured by utilization of an organic acid in the formulation of
the additive.
The purpose of a low molecular alcohol used in the system is to serve as a
dispersability agent for making the system field friendly.
The viscoelastic properties imparted to stimulation fluid are controlled by
three
mechanisms:
1. By varying total additive added to the stimulation fluid (0.1-5.0% by
volume);
2. By controlling the ratio between the organic/inorganic salt and the
glycinate (0.15-0.6% of glycinate); and
3. By controlling or adjusting the pH of the fracturing fluid system.
Another novel use of amphoteric surfactant is the utilization of change in its
ionic properties with pH to control the break viscosity lowering mechanism of
the gel.
As the pH of the system is increased above 6.5 the ionic properties of the
glycinate
change from cationic to anionic. This change de-stabilizes the micellar
structure,
hence, resulting in the break of the gel, allowing for easy post frac cleanup.
In the
earlier technologies, to attain a break the system had to encounter formation
fluids (oil
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CA 02354789 2004-09-09
andlor water) in order to de-stabilize the gel structure. Simple adjustment in
pH did
not break the gel in the earlier inventions. This limited the use of the
system to those
wells that contained oil or those that produced condensate. In the present
invention
the pH of the system can be increased easily by utilization of alkaline
compounds
such as carbonates, oxides, amines and etc.
As the temperature of the system increases the interaction between the ion
weakens, resulting in decrease in stability of the micelles. The upper limit
of the gel
appears to be around 65°C. The upper temperature range may be further
increased
by utilization with alternative salts or using a surfactant with different
length of the
alkyl group.
In a broad aspect, then, the present invention relates to a fracturing fluid
comprising:
(i) a surfactant having the general formula
R,
R3N+CH2C00-
R2
where R,-R2 are each an aliphatic group of C1-C4, branched or straight
chained, saturated or unsaturated, R3 is a group of C12-22, branched, straight
or cyclic, saturated or unsaturated;
(ii) a water soluble or dispersible anionic organic or inorganic salt;
(iii) an acid; and
(iv) a low molecular weight organic solvent
wherein the viscosity of the fluid is lowered by raising the pH thereof.
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According to a further aspect of the present invention, there is also provided
a visco-elastic fluid for fracturing a subterranean formation, the viscosity
of the fluid
being breakable subsequent to fracturing, said visco-elastic fluid comprising:
(i) a surfactant having the general formula
R,
R3N+CH2C00-
RZ
where R,-R2 are each an aliphatic group of C1-C4, branched or straight
chained, saturated or unsaturated, R3 is a group of C12-22, branched, straight
or cyclic, saturated or unsaturated;
(ii) a water soluble or dispersible anionic organic or inorganic salt;
(iii) an acid; and
(iv) a low molecular weight organic solvent.
According to yet another aspect of the present invention, there is also
provided
a method of fracturing a subterranean formation comprising the steps of:
providing a visco-elastic surfactant based hydraulic fracturing fluid
comprising:
(i) a surfactant having the general formula
R,
R3N+CHZCOO-
R2
where R,-R2 are each an aliphatic group of C1-C4, branched or straight
chained, saturated or unsaturated, R3 is a group of C12-22, branched, straight
or cyclic, saturated or unsaturated;
(ii) a water soluble or dispersible anionic organic or inorganic salt;
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CA 02354789 2004-09-09
(iii) an acid; and
(iv) a low molecular weight organic solvent,
pumping said fracturing fluid through a well bore and into a subterranean
formation at a sufficient pressure to cause fracturing of said formation; and
lowering the viscosity of said fluid subsequent to said fracturing to
facilitate
formation clean-up.
According to yet another aspect of the present invention, there is also
provided
a fluid for fracturing a subterranean formation and for use with a breaker
system, said
fluid comprising:
(i) a surfactant having the general formula
R~
R3N+CH2C00-
R2
where R,-R2 are each an aliphatic group of C1-C4, branched or straight
chained, saturated or unsaturated, R3 is a group of C12-22, branched, straight
or cyclic, saturated or unsaturated;
(ii) a water soluble or dispersible anionic organic or inorganic salt; and
(iii) an acid.
According to yet a further aspect of the present invention, there is also
provided a method of fracturing a subterranean formation comprising the steps
of:
providing a visco-elastic surfactant based hydraulic fracturing fluid
comprising:
(i) a surfactant having the general formula
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R,
R3N+CH2C00-
R2
wherein R,-R2 are each an aliphatic group of C1-C4, branched or straight
chained, saturated or unsaturated, R3 is a group of C12-22, branched, straight
chained or cyclic, saturated or unsaturated;
(ii) a water soluble or dispersible anionic organic or inorganic salt; and
(iii) an acid; and
(iv) a low molecular weight organic solvent, and;
pumping said fracturing fluid through a well bore and into a subterranean
formation at a sufficient pressure to cause fracturing of said formation
including the further step of lowering the viscosity of said fluid by raising
the
pH thereof.
The attached drawing is a graph of viscosity % against pH.
It will be observed, then, that the present invention is a four component
system, although the four components are typically combined into a single
component prior to addition to the fluid being viscosified. The primary
component,
the surfactant, is preferably a dihydroxyethyl tallow glycinate having the
structure:
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CH2CH20H
C~,6_,B~IN+CH2C00-
CHZCH20H
The second component, the salt is preferably sodium xylene sulfonate.
However, other similar salts may be used, such as potassium, zinc, ammonium,
magnesium (etc.) xylene or toluene sulfonate. In addition, other naphthalene
backboned sulfonate salts may be used. Inorganic salts such as sodium chloride
or
potassium chloride (KCL) can also be used.
As to the acid component, any organic or mineral acid may be used to lower
the pH below 6.5. Acids that have been found to be useful include formic acid,
citric
acid, hydrochloric acid, and so on. The preferred acid is acetic acid because
it is
universally available, low cost, and safe to handle.
The final component, the alcohol solvent is used to modify the viscosity of
the
solvent, usually water, by altering its polarity, which will result in reduced
viscosity of
the miscellar formations.
In an aqueous fluid, the surfactant composition of the present invention is
added in a concentration of from about 0.1 % wt to about 5.0% wt. The actual
composition in a preferred composition will be, for example:
Glycinate 0.65
Organic salt0.20
Acid 0.025
Solvent 0.125
Some variations, up to about 50% per component, are possible.
Unfoamed, the upper temperature limit of the present invention is about
65°C.
However, formulation of the present invention is also compatible with CO2, NZ
and
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C02, N2, air and low molecular weight hydrocarbon gas foams, over a
temperature
range of 5°C - 80°C.
The addition of Nitrogen (N2) or Carbon Dioxide (C02) as either a liquid or
gas
can dramatically improved the flow back characteristics of fracture fluids
especially
in under pressured reservoirs. Not only is the amount of fluid required for
the job
reduced, the hydrostatic head of the well bore fluid is lowered and the well
can flow
on its own. High pumping pressures will compress Nitrogen bubbles during
placement of the stimulation treatment only to expand when pressures are bled
off
and the treatment is flowed back. The fluid contains 10-200 standard cubic
metres
of Nitrogen or Carbon Dioxide per cubic metre of fluid.
Liquid or gaseous C02 can also be used to act as the energizing phase,
although it is pumped as a liquid and returns to surfaces as a gas. The
thermodynamic properties of liquid/gaseous C02 make it a unique fluid for
fracturing.
The fluid is pumped at low temperatures of typically - 5 to -25° C and
it remains as
a critical fluid (single phase) while the fracture is created and the proppant
placed.
Liquid C02 that leaks off from the fracture quickly rises to reservoir
temperature,
increasing its specific volume and becoming more like a gas. When the pressure
is
dropped and the well is flowed the single phase fluid returns to surface as
C02 vapor.
Treatment design for N2 energized fluid systems typically utilizes N2 pumped
at ratios of 40 - 60 scm/m3, which means standard cubic meters of Nitrogen gas
per
cubic meter of fluid (water). This is normally sufficient to allow the well to
flow
unassisted with reservoir pressure gradients of 6 kPa/m or higher. For
energized
C02 systems, liquid C02 is added at equivalent ratios, once the conversion
from liquid
to gas is made (543 scm/m3). Combined down hole fracturing pump rates are
approximately 3.5m3/min.
Foam Fracturin4
When liquid C02 is used as the energizing medium, the resulting mixture is
often referred to as an emulsion, since both phases are liquids. However,
herein the
term foam is used for describing both N2 or Liquid or gaseous C02 foamed
systems.
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A foam fracture treatment consists of nitrogen (typically 75%) dispersed as
small
bubbles throughout a continuous liquid phase. In traditional foams, the liquid
phase
contains surfactants and gellants to prevent coalescence and resulting phase
separation. Foam quality (N2 or Liquid C02) should range from 52 - 95% (ratio
of gas
volume to foam volume). Above 95% the mixture can be defined as a mist with
the
gas becoming the continuous phase. Below 52% there is no bubble to bubble
interference and therefore a stable foam does not exist. Above 52% the gas
concentration is high enough for the bubbles to interfere and deform, thereby
imparting resistance to shear and increasing the viscosity of the fluid
system.
Unlike conventional foams that utilize long-chained polymers to viscosify the
external phase, the present invE;ntion, foamed, uses a combination of
surfactants to
impart viscosity to the water phase. The chemical structure that is formed
produces
a three-dimensional matrix of molecules that interfere with each other and
raise the
apparent viscosity of the base fluid system. Combined with either N2 or Liquid
C02,
foam viscosities are generated as a function of foam quality and the fluid
system
develops all of the properties desired for a fracture fluid system. The use of
surfactants also produces a fluid with strong foaming tendencies that aids the
return
of fluids from the reservoir when foamed with the producing hydrocarbon gas.
Field Trials
With depths ranging from 450 - 1600 m, trial stimulation treatments have
focussed on Cretaceous sandstones that range in reservoir pressure from 2 - 7
kPa/m. Fracture fluid cleanup has been reported as superior to conventional
foams
utilizing polymer base gels. Some of the stimulated reservoirs include
Glauconite,
Dinosaur Park, Bad Heart, Viking, Belly River, Colony, Sunburst, Bluesky,
Dunvegan,
Mannville, and Bow Island. Long term production data is not available at this
time,
but comments from trial operations are very positive on fast clean-up and
initial
production. Also, these reservoirs represent trial stimulation work to date
and do not
suggest any limitations on the potential for usage on other gas-bearing
reservoirs.
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Tyra~ical Treatments
JOB TYPE LOCATION FORMATION AVERAGE RATEPROPPANT
VOL.
FRAC GRADIENT'DEPTH AVE. PRESSUREMAX CONC.
N2 Energized 69-22W5 Bad Heart 2.8 m3/min 25 tonne
CWS 400 22 kPa/m 625 m 9.5 Mpa 1070 kg/m3
C02 Energized17-24W4 Ostracod 2.8 m3/min 10 tonne
CWS 400 18 kPa/m 1668 m 27.0 Mpa 1012 kg/m3
Nz Foamed 33-5W4 Colony 3.4 m3/min 15 tonne
CWS 400 22 kPa/m 858 m 18.3 Mpa 743 kg/m'
COz Foamed 20-26W4 Belly River 4.2 m'/min 5 tonne
CWS 400 17 kPa/m 969 m 12.0 Mpa 560 kg/m3
Note: CWS 400 is the fluid of the present invention.
Post Fracture Flow Rate Comparison
JOB TYPE LOCATION MEDICINE L. MILK RIVERU. MILK RIVER
HAT FLOW RATE FLOW RATE
FLOW RATE
Nz Energized 21-17W4 11,680 m'Iday2,650 m3/day1,200 m3/day
Borate
NZ energized 21-17W4 10,860 m'/day4,610 m3/day2,700 m3/day
CWS 400
Lab Test Data
The following examples are used to illustrate viscosifying properties of the
fluid
of the present invention.
Example #1
Following additives were added to the water while stirring:
Glycinate 0.520 volume
Sodium Xylene Sulfonate 0.152 volume
Glacial Acetic Acid 0.040 volume
Isopropyl Alcohol 0.088 volume
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Results:
Upon completion of addition of the additives. Viscoelastic gel was observed
to be present in the container. The rheological properties of the gel were
measured using Brookfield LVT viscometer with spindle #1 and the guard leg
attached.
Speed~,RPM~ Viscosit cP
100 10.9
60 14.T
50 16.4.
30 23.2'
29.4
12 39.5~
Example #2
Following additives were added to the water while stirring.
15 Glycinate 1.30 volume
Sodium Xylene Sulfonate 0.32 volume
Glacial Acetic Acid 0.10 volume
Isopropyl Alcohol 0.22 volume
Results:
20 Upon completion of addition of the additives. Viscoelastic gel was observed
to be present in the container. The rheological properties of the gel were
measured using Brookfield t_VT viscometer with spindle #1 and the guard leg
attached.
Speed ~RPM~ Viscosit cP
60 71.T
50 83.5~
127.4
20 178..8
12 267. 0
30 6 414
3 532
1.5 592
0.6 670
0.3 740
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Conclusion:
The two examples clearly demonstrate viscosifying properties of surfactants.
These
viscosities are deemed sufficient for fracturing.
The novel surfactant based system of the present invention can not only be
used for viscosifying water but also can be used for viscosifying mineral,
organic
and/or inorganic acids. The rheological properties imparted by the system will
be
dictated by type of acid and strength of acid being used. Typical acid used
are HC1
(10-34%, Acetic Acid, Formic Acid, Sulfamic Acid, HC1/HF acid mixture etc.)
Typically, viscosified acids are used in stimulation of: hydrocarbon bearing
formation,
water injection wells, and disposal wells to improve production or injectivity
of the
reservoir. Viscosified acids have an advantage over non-viscosified acid, as
the
reaction rate of the acid to the formation rock is proportional to viscosity
of acid
mixture. By retarding the acid reactivity through the gellation process,
deeper acid
penetration in more controlled fashion is accomplished. This typically creates
better
flow channels between reservoir and the well.
The viscosifying acid with surfactant alternative embodiments of the present
invention has an additional advantage compared to the conventional polymer
methods of viscosifying acid. That is, as the acid reaction proceeds with the
formation, product from this reaction produce salts that act as a breaker to
viscosified
acid. This allows to cleanup-spent acid more easily.
It will also be understood by one skilled in the art that altering the ratio
of
additives in either embodiment of the present invention can control the
rheological
properties.
In order to lower the viscosity of the surfactant based fracturing fluid of
the
present invention, the pH of the fluid is raised by the addition of an
alkaline substance
such as magnesium oxide or sodium hydroxide. This effectively raises the
critical
micelle concentration of the fluid, resulting in disassociation of the
micelles that have
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CA 02354789 2001-08-07
been formed. Accordingly, it will be understood that formation clean-up is
quickly
accomplished, without caking or clogging.
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