Note: Descriptions are shown in the official language in which they were submitted.
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Description
Process for producing mineral oil from underground mineral oil deposits
The present invention relates to a process for producing mineral oil from
mineral oil deposits, in
which the mineral oil yield is increased by blocking highly permeable regions
of the mineral oil
formation by separate injection of at least two different formulations into
the deposit, said
formulations not mixing with one another until within the deposit, and the
mixture forming highly
viscous gels under the influence of the deposit temperature. The process can
be used
especially in the final stage of deposit development, when watering out in
production increases,
and particularly after the steam flooding of the deposits.
In natural mineral oil deposits, mineral oil occurs in cavities of porous
reservoir rocks which are
closed off from the surface of the earth by impervious covering layers. In
addition to mineral oil,
including proportions of natural gas, a deposit further comprises water with a
higher or lower
salt content. The cavities may be very fine cavities, capillaries, pores or
the like, for example
those having a diameter of only approx. 1 pm; the formation may additionally
also have regions
with pores of greater diameter and/or natural fractures.
After the borehole has been sunk into the oil-bearing strata, the oil at first
flows to the
production boreholes owing to the natural deposit pressure, and erupts from
the surface of the
earth. This phase of mineral oil production is referred to by the person
skilled in the art as
primary production. In the case of poor deposit conditions, for example a high
oil viscosity,
rapidly declining deposit pressure or high flow resistances in the oil-bearing
strata, eruptive
production rapidly ceases. With primary production, it is possible on average
to extract only 2 to
10% of the oil originally present in the deposit. In the case of higher-
viscosity oils, eruptive
production is generally completely impossible.
In order to enhance the yield, what are known as secondary production
processes are therefore
used.
The most commonly used process in secondary mineral oil production is water
flooding. This
involves injecting water through the injection boreholes into the oil-bearing
strata. This artificially
increases the deposit pressure and forces the oil out of the injection
boreholes to the production
boreholes. By water flooding, it is possible to substantially increase the
yield level under
particular conditions.
In the ideal case of water flooding, a water front proceeding from the
injection borehole should
force the oil homogeneously over the entire mineral oil formation to the
production borehole. In
practice, a mineral oil formation, however, has regions with different levels
of flow resistance. In
addition to oil-saturated reservoir rocks which have fine porosity and a high
flow resistance for
water, there also exist regions with low flow resistance for water, for
example natural or
synthetic fractures or very permeable regions in the reservoir rock. Such
permeable regions
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may also be regions from which oil has already been recovered. In the course
of water flooding,
the flooding water injected naturally flows principally through flow paths
with low flow resistance
from the injection borehole to the production borehole. The consequences of
this are that the
oil-saturated deposit regions with fine porosity and high flow resistance are
not flooded, and that
increasingly more water and less mineral oil is produced via the production
borehole. In this
context, the person skilled in the art refers to "watering out of production".
The effects
mentioned are particularly marked in the case of heavy or viscous mineral
oils. The higher the
mineral oil viscosity, the more probable is rapid watering out of production.
For production of mineral oil from deposits with high mineral oil viscosity,
the mineral oil can
also be heated by injecting steam into the deposit, thus reducing the oil
viscosity. As in the case
of water flooding, however, steam and steam condensate can also strike
undesirably rapidly
through highly permeable zones from the injection boreholes to the production
boreholes, thus
reducing the efficiency of the tertiary production.
The prior art discloses measures for closing such highly permeable zones
between injection
boreholes and production boreholes by means of suitable measures. As a result
of these, highly
permeable zones with low flow resistance are blocked and the flood water or
the flood steam
flows again through the oil-saturated, low-permeability strata. Such measures
are also known
as "conformance control". An overview of measures for conformance control is
given by Borling
et al. "Pushing out the oil with Conformance Control" in Oilfield Review
(1994), pages 44 if.
For conformance control, it is possible to use comparatively low-viscosity
formulations of
particular chemical substances which can be injected easily into the
formation, and the viscosity
of which rises significantly only after injection into the formation under the
conditions which exist
in the formation. To enhance the viscosity, such formulations comprise
suitable inorganic,
organic or polymeric components. The rise in viscosity of the injected
formulation can firstly
occur with a simple time delay. However, there are also known formulations in
which the rise in
viscosity is triggered essentially by the temperature rise when the injected
formulation is
gradually heated to the deposit temperature in the deposit. Formulations whose
viscosity rises
only under formation conditions are known, for example, as "thermogels" or
"delayed gelling
systems".
SU 1 654 554 Al discloses a process for extracting oil using mixtures of
aluminum chloride or
aluminum nitrate, urea and water, which are injected into the mineral oil
formation. At the
elevated temperatures in the formation, the urea is hydrolyzed to carbon
dioxide and ammonia.
The release of the ammonia base significantly increases the pH of the water,
and results in
precipitation of a highly viscous gel of aluminum hydroxide, which blocks the
highly permeable
zones.
US 2008/0035344 Al discloses a mixture for blocking underground formations
with delayed
gelation, which comprises at least one acid-soluble crosslinkable polymer, for
example partly
hydrolyzed polyacrylamide, a partly neutralized aluminum salt, for example an
aluminum
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hydroxide chloride, and an activator which can release bases under formation
conditions, for
example urea, substituted ureas or hexamethylenetetramine. The mixture can
preferably be
injected at a temperature of 0 to 40 C, and gelates at temperatures above 50
C, according to
the use conditions, within 2 h to 10 days.
RU 2 339 803 C2 discloses a process for blocking such highly permeable zones,
in which the
volume of the highly permeable zones to be blocked is first of all determined.
Subsequently, in a
first process step, an aqueous formulation composed of carboxymethylcellulose
and chromium
acetate as a crosslinker is injected at 15% by volume, based on the total
volume of the zone in
the mineral oil formation to be blocked. In a second step, an aqueous
formulation of
polyacrylamide and a crosslinker is injected.
RU 2 361 074 discloses a process for blocking highly permeable zones, in which
portions of
formulations based on urea and aluminum salts are injected into a deposit with
high deposit
temperature.
L. K. Altunina and V. A. Kuvshinov in Oil & Gas Science and Technology - Rev.
IFP, Vol. 63
(2008) (1), pages 37 to 48 describe different thermogels and the use thereof
for oil production,
including thermogels based on urea and aluminum salts, and thermogels based on
cellulose
ethers.
US 4,141,416 discloses a process for tertiary mineral oil production, in which
an aqueous
alkaline silicate solution is injected into a mineral oil formation to lower
the water-oil interfacial
tension, thus reducing the oil-water interfacial tension. In one variant, it
is possible
simultaneously to close permeable regions of the mineral oil formation, by
injecting additional
components in a second step, for example acids which can form precipitates
with the alkaline
silicate solution.
RU 2 338 768 C1 discloses a process for blocking permeable zones in oil
deposits, in which a
solution comprising sodium phosphate, sodium oxalate, sodium carbonate and a
mixture of
carboxymethylcellulose and xanthan, and also a second solution comprising
calcium chloride,
copper chloride and aluminum chloride, are each injected separately into the
mineral oil
formation, and the two formulations do not mix until underground. In order to
prevent premature
mixing, it is possible to inject a portion of water into the mineral oil
formation between the two
formulations. After mixing, the formulations form precipitates of sparingly
soluble hydroxides
and sparingly soluble calcium salts. The specification does not disclose any
combination of the
process with steam flooding. Nor does it disclose precipitation as a function
of temperature.
Instead, the precipitates are formed without a delay when the two solutions
are mixed. In this
way it is difficult to block those areas of the formation that are at a
greater distance from the
injector.
Conformance control in connection with steam flooding, however, presents a
series of particular
difficulties. Steam used for steam flooding typically has a temperature of
more than 300 C.
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Accordingly, the mineral oil formation may heat up to more than 300 C at the
site of the injection
borehole. Although the temperature decreases with increasing distance from the
injection
borehole, long-lasting, permanent steam flooding frequently causes the
temperature to decline
back to the natural deposit temperature only several hundred meters away from
the steam
injection, and even the very hot zone around the injection borehole may have a
considerable
extent. After prolonged steam flooding, a hot zone of 250 C to 300 C may form
in a radius of
several meters around the injection borehole. This zone may have a radius of
up to 40 meters
when the deposit has a relatively homogeneous permeability. In the case of a
deposit which has
highly permeable channels, and the steam accordingly flows predominantly
through the highly
permeable channels, the hot zone may also extend over even greater distances.
On the one hand, many formulations of the prior art, especially those based on
organic
materials, are no longer sufficiently stable at the temperatures which may
prevail after steam
flooding in a mineral oil formation.
The gel-forming formulations identified above, comprising aluminum salts and
urea, have a very
good temperature stability, and thus in principle are also suitable for
formations after steam
flooding. With such formulations, however, the problem arises that the time
until the
abovementioned gel-forming formulations actually form gels depends not only on
the
composition and the concentration of the components but of course on the
temperature, and the
higher the temperature, the more rapidly gel is formed. While gel formation at
temperatures of
50 to 120 C can take hours, days or even weeks, gel is of course formed more
rapidly at higher
temperatures: L. K. Altunina and V. A. Kuvshinov present, in Oil & Gas Science
and Technology
- Rev. IFP, Vol. 63 (2008) (1), pages 37 to 48, Figure 2, page 39,
measurements for a get-
forming formulation in the form of aluminum salts and urea. At 150 C gel
formation sets in after
40 min, at 200 C after 20 min, and at 250 C after 10 min. When such
formulations are injected
into a hot injection borehole or a hot formation, there is the risk that gel
formation will set in
already in the immediate zone around the injection borehole, since the flow
rate of the
formulation in the mineral oil formation is usually so low that it is heated
up very rapidly after the
injection.
Thus, the injected formulations completely fail to reach the highly permeable
zones that they are
actually supposed to block, and viscous gels are instead formed at the
injection borehole or in
the zone close to the borehole. The gels can hinder the further pumping of the
gel-forming
formulation, and subsequent water or steam flooding can of course also be
prevented.
The problems can be partly solved by allowing the steam injected to cool a
little after the
injection of steam, or additionally injecting water for cooling, but such a
procedure takes time
and does not guarantee flawless pumping of the gel-forming formulations into
the deposit.
It was therefore an object of the invention to provide a process for producing
mineral oil from
mineral oil formations with very hot zones, in which the watering out of
production is reduced
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and the oil recovery rises, and which can also be executed directly after
steam flooding of the
mineral oil formation.
Accordingly, a process has been found for producing mineral oil from
underground mineral oil
5 deposits into which at least one injection borehole and at least one
production borehole have
been sunk, said process comprising at least the following process steps:
(1) injection of steam into at least one injection borehole and withdrawal of
mineral oil
through at least one production borehole, the temperature at the injection
borehole
after process step (1) being 90 C to 320 C, and
(2) blocking of highly permeable zones in the mineral oil deposit in the
region between
the at least one injection borehole and the at least one production borehole
by
injecting aqueous formulations through at least injection borehole, said
formulations
comprising water and chemical components which, after injection into the
deposit,
can form gels under the influence of the deposit temperature,
(3) continuing of the production of mineral oil through at least one
production borehole,
and which comprises performing process step (2) by injecting at least
= an acidic formulation F1 which comprises at least water and a water-soluble
aluminum(III) salt and/or a partially hydrolyzed aluminum(III) salt, and
= a formulation F2 which comprises at least water and at least one water-
soluble
activator which causes an increase in the pH when heated to a temperature of
> 50 C, the activator being a compound selected from the group of urea and
substituted water-soluble ureas,
each separately into the deposit, the formulations mixing with one another in
the formation after
injection, and forming viscous gels after heating under the influence of the
deposit.
In a preferred embodiment, three portions of the formulation are injected in
succession, to be
precise, in the sequence F1 - F2 - F1 or F2 - F1 - F2.
The process according to the invention has the advantage that it is also
possible to selectively
block highly permeable zones in deposits with high temperature by means of
suitable gels. The
process enables direct performance of the profile modification in the hot
carrier directly after the
steam flooding. The distance between the borehole and the gel bank is thus
controllable. This
achieves efficient blocking of highly permeable zones, reduces watering out of
production and
increases oil recovery.
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Index of drawings:
Fig. 1 Schematic diagram of the temperature profile in an oil deposit after
prolonged
steam flooding
Fig. 2 Diagram of the pressure profile of a core flooding test using
formulations F1 and
F2
Fig. 3 Schematic diagram of the mixing of two formulations F1 and F2.
Fig. 4 Schematic diagram of the mixing of three portions F1, F2 and F1
injected in
to succession.
Fig. 7
With regard to the invention, the following specific details are given:
The process according to the invention for production of mineral oil is a
process for secondary
or tertiary mineral oil production, i.e. it is employed after primary mineral
oil production has
stopped owing to the autogenous pressure of the deposit, and the pressure in
the deposit has to
be maintained by injecting water and/or steam.
Deposits
The deposits may be deposits for all kinds of oil, for example those for light
or heavy oil. In one
embodiment of the invention, the deposits are heavy oil deposits, i.e.
deposits which comprise
mineral oil with an API gravity of less than 22.3 API.
To perform the process, at least one production borehole and at least one
injection borehole are
sunk into the mineral oil deposit. In general, one deposit is provided with
several injection
boreholes and with several production boreholes.
The initial deposit temperature - i.e. the temperature before employment of
the process
according to the invention - is typically in the range from 25 C to 150 C,
preferably 30 C to
140 C, more preferably 35 C to 130 C, even more preferably 40 C to 120 C, and,
for example,
50 to 110 C. The deposit temperature changes as a result of employment of the
process
according to the invention, at least in the region between the injection
boreholes and the
production boreholes.
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Process
According to the invention, the process comprises at least three process steps
(1), (2) and (3),
which are performed in this sequence, but not necessarily in immediate
succession. The
process may of course comprise further process steps, which can be performed
before, during
or after steps (1), (2) and (3).
Process step (1)
In a first process step, (1), steam is injected into the at least one
injection borehole and mineral
oil is withdrawn through at least one production borehole. The term "mineral
oil" in this context
of course does not mean single-phase oil, and what is meant is instead the
customary
emulsions which comprise oil and formation water and are produced from mineral
oil deposits.
The steam injected generally has a temperature of up to 320 C, especially 250
C to 320 C and
preferably 280 C to 320 C.
As a result of the injection of steam, there forms, in the region between the
injection borehole
and the production borehole, a zone in which oil is displaced by steam or
water (formation water
or water formed by condensation of steam).
As a result of the injection of steam, the temperature at the injection
borehole increases, and at
the end of process step (1) is 90 C to 320 C. In particular, the temperature
at the injection
borehole(s) after process step (1) is 120 C to 320 C, preferably 150 C to 300
C, more
preferably 180 C to 300 C and, for example, 250 to 300 C.
As a result of the injection, there also forms a hot zone around the injection
borehole. The hot
zone may have a radius of approx. 5 m up to approx. 50 m around the injection
borehole,
depending on the flood time, flood volume and temperature of the steam. When a
plurality of
injection boreholes are present and steam is injected through each of the
injection boreholes,
such a hot zone forms around each of the injection boreholes.
As a result of the flow of steam or condensed water or heated formation water
from the injection
boreholes in the direction of the production boreholes, the entire region
between the at least
one injection borehole and the at least one production borehole can heat up to
temperatures
above the natural deposit temperature, the heating of course decreasing with
increasing
distance from the injection borehole(s).
These facts are shown schematically and illustratively in figure 1. Figure 1
shows a schematic of
a section of a mineral oil deposit which has a steam injector and a production
borehole present
at a certain distance therefrom. The original deposit temperature is To. As a
result of injection of
hot steam, the deposit temperature increases to an ever greater degree with
time proceeding
from the injection borehole. Figure 1 shows the temperature profiles after 3,
5 and 7 years of
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steam injection, and at the breakthrough of the steam (curve D) from the
injection borehole to
the production borehole.
The upper temperature limit in the hot zone corresponds to the upper
temperature limit at the
injection borehole. However, according to the duration of the steam injection,
it may be lower
with increasing distance from the injection borehole.
Process step (2)
Process step (2) may be employed as soon as production is subject to excessive
watering out,
or a steam breakthrough is registered. In the event of a steam breakthrough,
steam flows
through highly permeable zones from the injection borehole to the production
borehole.
However, highly permeable zones need not necessarily be generated by the steam
flooding, but
may also be present naturally in a formation. In addition, it is possible that
permeable zones
have already been created in a process step preceding the process according to
the invention.
To prepare for process step (2), it is advantageous to measure the temperature
in the region of
the injection borehole and to determine the temperature field of the deposit
in the region
affected by the flooding. Methods for determining the temperature field of a
mineral oil deposit
are known in principle to those skilled in the art. The temperature
distribution is generally
undertaken from temperature measurements at particular sites in the formation,
in combination
with simulation calculations, which take account of factors including amounts
of heat introduced
into the formation and the amounts of heat removed from the formation.
Alternatively, any of the
regions can also be characterized by the average temperature thereof. It will
be clear to the
person skilled in the art that the outlined analysis of the temperature field
constitutes merely an
approximation of the actual conditions in the formation.
Process step (2) can be performed immediately after process step (1).
Before the execution of process step (2), it is, however, optionally possible
to lower the
temperature in the region of the injection borehole in order to facilitate the
trouble-free
performance of process step (2). This can be accomplished by simply waiting.
In a further
embodiment of the invention, cold water can optionally be injected into the
injection borehole,
thus reducing the temperature in the region of the injection borehole and in
the zone close to
the borehole.
In the course of process step (2), highly permeable zones in the mineral oil
deposit in the region
between the injection boreholes and the production boreholes are blocked by
injection of
aqueous formulations through the at least one injection borehole.
According to the invention, for this purpose, at least two different aqueous
formulations F1 and
F2 are used. The formulation F1 comprises at least water and one or more water-
soluble
aluminum(III) salt and/or a partially hydrolyzed aluminum(III) salt, and
formulation F2, which is
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different therefrom, comprises at least water and one or more water-soluble
activators which
cause an increase in the pH when heated to a temperature of > 50 C. The
increase in the pH
gives rise to aluminum compounds which are poorly soluble.
To execute the process, the at least two formulations F1 and F2 are each
injected separately
through one or more injection boreholes into the deposit. These are the same
injection
boreholes which have been used in process step (1) for injection of steam.
The injection is undertaken in such a way that the two formulations mix in the
formation after
injection.
Formulations F1 and F2
According to the invention, the compositions of formulations F1 and F2, with
regard to the
chemical components thereof, are such that, after mixing underground, they
form viscous gels
under the influence of the deposit after heating to a minimum temperature T >
50 C, while the
separate, unmixed formulations F1 and F2 cannot form gels even under the
influence of the
deposit temperature. The viscous gels formed block cavities in the mineral oil
formation, thus
blocking flow paths for water and/or steam.
In accordance with the invention,
= formulation F1 is an acidic aqueous formulation which comprises at least
water and a
water-soluble aluminum(III) salt and/or a partially hydrolyzed aluminum(III)
salt, and
= formulation F2 is an aqueous formulation which comprises at least water and
a water-
soluble activator which causes an increase in the pH when heated to a
temperature of
> 50 C.
In addition to water, the formulations may optionally comprise further, water-
miscible organic
solvents. Examples of such solvents comprise alcohols. In general, the
formulations (F),
however, should comprise at least 80% by weight of water, based on the sum of
all solvents in
the formulation, preferably at least 90% by weight and more preferably at
least 95% by weight.
Most preferably, only water should be present.
The water-soluble aluminum(III) salts may be, for example, aluminum chloride,
aluminum
bromide, aluminum nitrate, aluminum sulfate, aluminum acetate or aluminum
acetylacetonate.
These aluminum compounds may also be already partly hydrolyzed aluminum(Ill)
salts, for
example aluminum hydroxychloride. It will be appreciated that it is also
possible to use mixtures
of two or more different aluminum compounds. The pH of formulation F1 is <_ 5,
preferably <_ 4.5
and more preferably < 4. These aluminum compounds are preferably aluminum(Ill)
chloride
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and/or aluminum(lII) nitrate. When reacted with bases, aluminum(III) salts
which are dissolved
in water form poorly soluble water-containing gels.
The water-soluble activators in formulation F2 release bases when heated to a
temperature of >
5 50 C in an aqueous medium, and thus ensure an increase in the pH of the
solution. The water-
soluble activators used may, for example, be urea and substituted water-
soluble ureas such as
N,N'-alkylureas, especially N-methylurea, N,N'-dimethylurea or N,N'-
dimethylolurea. Urea and
the stated urea derivatives are hydrolyzed in an aqueous medium to ammonia or
amines and
CO2. The rate of hydrolysis is, of course, dependent on the temperature, and
increases as the
10 temperature increases. It will be appreciated that it is also possible to
use mixtures of two or
more different activators. For execution of the present invention, preference
is given to urea. It
will be appreciated that in addition to the stated activators, the
formulations may comprise still
more water-soluble activators.
Formulations F1 and F2 may additionally comprise further components which can
accelerate or
slow gel formation. Examples comprise further salts or naphthenic acids. In
addition,
formulations F1 and F2 may also comprise thickening additives, for example
thickening
polymers.
After mixing formulations F1 and F2 and heating to temperatures of > 50 C, the
increase in the
pH forms high-viscosity, water-insoluble gels which comprise metal ions,
hydroxide ions and
possibly further components. In the case of use of aluminum compounds, an
aluminum
hydroxide or aluminum oxide hydrate gel may form, which may of course comprise
further
components, for example the anions of the aluminum salt used.
In the preferred variant, it has been found to be useful, in formulation F1,
to use the
aluminum(III) salts or the partially hydrolyzed aluminum(III) salts, in an
amount of 3 to 30% by
weight, preferably 5 to 25% by weight, based on the sum of all components of
the formulation,
this figure being based on anhydrous metal compounds.
It has likewise been found to be useful, in formulation F2, to use the water-
soluble activator(s) in
an amount of 3 to 60% by weight, preferably 10 to 45% by weight, based on the
sum of all
components.
The concentration of the activator should therefore be such that a sufficient
amount of base can
form to lower the pH to such an extent that a gel can indeed precipitate out.
In the case of
aluminum(III) salts, the amount of the activator should at least be such that
3 mol of base are
released per mole of Al(lll). In the case of partially hydrolyzed Al(III)
salts, it can be less
satisfactory depending on the degree of hydrolysis.
The concentration of the components can in principle also be used to determine
the time until
gel formation after mixing, although it should be considered that the mixing
of formulations F1
and F2 in the formation need not be complete, and that a certain degree of
uncertainty
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accordingly remains in the adjustment of gel formation times. The higher the
concentration of
the activator, the greater the rate of gel formation - at a given
concentration of the metal
compound. This connection can be utilized by the person skilled in the art in
order to prolong or
to shorten the gel formation time in a controlled manner.
In table 1 below, the time until gel formation of a gel-forming formulation is
compiled by way of
example for different temperatures, the formulation having been obtained by
mixing two
formulations F1 and F2. F1 comprises 16% by weight of AIC13 (calculated as
anhydrous
aluminum chloride) and 84% by weight of water, and F2 comprises 50% by weight
of urea and
50% by weight of water. The mixture accordingly comprises 8% by weight of
AICI3, 25% by
weight of urea and 67% by weight of water.
Temperature [ C] 100 90 80 70 60
Gel formation time [days] 1/4 1 3 6 30
Table 1: Time until gel formation at different temperatures
Table 2 below shows the time until gel formation for different mixtures of
AICI3 (calculated as
anhydrous product), urea and water at 100 C or 100 C. It is seen that the time
until formation of
the gel becomes ever longer with decreasing amount of the urea activator.
F1 F2 Concentration of the AICI3 / urea weight Time until gel formation
AICI3 urea mixture ratio [h]
[% by wt.] [% by wt.] [% by wt.]
AICI3 Urea 100 C 110 C
8 32 4 16 1:4 4.0 -
8 24 4 12 1:3 4.3 -
8 16 4 8 1:2 7.3 -
8 8 4 4 1:1 19.0 -
16 60 8 30 1:3.75 5.3 2
4 15 2 7.5 1:3.75 - 8
16 48 8 24 1:3 5.5 -
16 32 8 16 1:2 8.3 -
16 16 8 8 1:1 18.0 -
16 12 8 6 1:0.75 23.0 -
Table 2: Time until gel formation ("-" no measurement). % by wt. relates to
the sum of all
components of the aqueous formulations F1 and F2 or mixture thereof.
The stated gels based on aluminum salts and urea can be used even at
relatively high
temperatures. L. K. Altunina and V. A. Kuvshinov in Oil & Gas Science and
Technology - Rev.
IFP, Vol. 63 (2008) (1), pages 37 to 48, present, in Figure 2 on page 39,
measurement values
for a gel-forming formulation in the form of aluminum salts and urea at
relatively high
temperatures. Gelling starts after 40 minutes at 150 C, after 20 minutes at
200 C, and after 10
minutes at 250 C.
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US 7,273,101 B2 discloses the use of mixtures comprising partially hydrolyzed
aluminum
chloride, for example AI2(OH)2C1 * 2.5 H20, and urea and/or urea derivatives
such as dimethyl
urea, for example, for forming gels. The mixtures may further comprise
inorganic particles, more
particularly finely divided Si02, or Si02 coated with aluminum compounds. The
specification
observes that the time to gelling in the temperature range from 45 to 140 C
can be set at 12 to
96 hours.
The formulations described, based on aluminum salts and activators, have the
advantage that
inorganic gels are formed. The gels are stable up to temperatures of 300 C and
are therefore
very particularly suitable for deposits with very high temperatures, such as
the present hot
deposits after steam flooding. In addition, the inorganic gels, if required,
can also be removed
again very easily from the formation, by injecting an acid into the formation
and dissolving the
gels.
Performance of process step (2)
According to the invention, the at least two formulations F1 and F2 are each
injected separately
into the deposit through one or more injection boreholes, and the formulations
do not mix until
underground. The injection of formulations F1 and F2 is generally followed by
flooding with
further water.
In this case, the formulations should mix with one another around the
injection borehole only
after passing through the first hot zone, in order that they actually reach
the highly permeable
zones in the mineral oil formation and do not form gels too early.
In order to achieve this, it is advisable to reduce the skin factor of the
borehole by known
technical measures, and to perform the pumping of the formulations F1 and F2
with maximum
injection rates and with maximum pressure. This results in the formulations
passing rapidly
through the hottest zone as soon as they have gone around the injection
borchole.
Advantageously, it is also possible, as already described above, to cool the
formation a little in
the zone close to the borehole before injection of formulations F1 and F2, for
example by water
flooding. It is also advisable to use, as mixing water for formulations F1 and
F2 and for optional
water flooding, water with a low temperature, especially water with a
temperature of less than
20 C. The injected formulations F1 and F2, respectively, ought to have a pre-
injection
temperature - that is a temperature prior to entry into the borehole - of less
than 40 C,
preferably less than 20 C, more preferably less than 10 C, and with particular
preference a
temperature of not more than 5 C above the freezing point of the solution.
In a further embodiment, a portion of water is injected between an injection
of formulations F1
and F2 or F2 and Fl. The volume of water injected here should be not greater
than, preferably
smaller than, the volume of the subsequently injected portion of F1 or F2. The
volume of such a
CA 02754554 2011-10-03
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13
portion of water may especially be 40% to 100% of the subsequently injected
portion, preferably
40 to 80% and more preferably 40 to 60%.
In a further preferred embodiment, a formulation F2 is injected first,
especially a formulation
comprising the water-soluble activator, especially a urea-comprising
formulation, and then at
least one formulation Fl. At the start of the hydrolysis from urea to C02 and
NH3, gas bubbles
are formed which increase the viscosity of the formulation. This aids the
mixing with the
following formulation Fl.
In this embodiment, formulation F2 may comprise a viscosity-increasing
additive, for example a
water-soluble thickening polymer, specifically in such an amount that the
viscosity of formulation
F2 under deposit conditions is somewhat greater than that of formulation F1
injected thereafter.
Examples of such polymers comprise polyacrylamide, microgels based on
polyacrylamide or
biopolymers. By virtue of the slightly higher viscosity, the flow rate of the
first injected portion of
formulation F2 in the formation is somewhat lower than that of the
subsequently injected
formulation Fl. Formulation F1 can accordingly penetrate particularly well
into the flowing front
of formulation F2 and mix therewith. In general, the viscosity of the injected
formulation F2
should not be more than 30% higher, for example 10% to 30% higher, than the
viscosity of the
formulation F1 injected beforehand.
In order to achieve extremely good blocking of high-permeability zones in
mineral oil formations,
the formulations F1 and F2 in the formation must be mixed as completely as
possible. Complete
mixing, however, may be hindered by gel formation itself, particularly at
relatively high
temperatures, if gel formation is already rapid.
This is shown by way of example in Figure 3. Figure 3 (top) shows a
formulation F1 and a
subsequently injected formulation F2, which flow through a high-permeability
region (1) of the
formation. The high-permeability region is surrounded by a low-permeability
region (2), drawn in
gray. When the formulation F2 has reached the formulation F1, a gel begins to
form at the
interface (Figure 3, bottom). This gel plug at least hinders the further
mixing of the formulations
F1 and F2. A substantial part of the initially injected formulation spreads
further, unused, in the
formation.
In a further preferred embodiment of the invention, therefore, 3 portions are
injected, namely
either a portion of formulation F2, a portion of formulation F1, and a further
portion of
formulation F2, or a portion of formulation F1, a portion of formulation F2,
and a further portion
of formulation Fl.
This embodiment and its advantages are shown by way of example in Figures 4,
5, 6 and 7.
Figure 4 shows three successively injected portions of F1, F2 and F1. When the
formulations
begin to mix, gel plugs begin to form at both interfaces between F1 and F2
(Figure 5).
Formulation F2 is enclosed between two gel plugs and can no longer flow on. As
a result of the
pressure of following water, the second portion of F1 is diverted into less
permeable regions as
well, from where it can flow back into the region in which the formulation F2
is located (Figure
CA 02754554 2011-10-03
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6). The direction of flow is indicated by the arrows 3. As a result, a
relatively large gel plug (4) is
formed (Figure 7). The same applies to injection in the order F2, F1 and F2.
The preferred embodiment described may be employed in principle at any
formation
temperature. However, it is particularly suitable when the temperature of the
formation at the
point at which the formulations mix is even higher than 80 C, more
particularly higher than
100 C, in particular higher than 120 C. The temperature may be situated, for
example, in the
range from 80 C to 200 C, 100 C to 200 C, 120 C to 200 C, 80 C to 150 C or 100
C to 150 C.
The preferred sequence is F2 - F1 - F2, in other words, the water-soluble
activator, more
particularly urea, is injected to begin with. The dissolution of urea in water
is endothermic, and
so the temperature of the formulation reduces by 10 to 15 C on dissolution. It
is then possible
advantageously to inject a cold solution. The temperature of formulation F2 on
injection ought
preferably to be less than 20 C, more preferably less than 15 C, and very
preferably less than
10 C.
In a variant of this embodiment, 3 portions, F1, F2, F1 or F2, F1, F2, are
pressed in
successively, the viscosity of the formulations increasing from the first to
the third formulation
injected. This can be done by using viscosity-increasing additives, more
particularly thickening
polymers. The increasingly higher viscosity has the effect that the
formulations do not mix too
rapidly. At higher temperatures, customary viscosity-raising polymers lose
their effect.
Accordingly, as soon as the formulations warm up under the influence of the
formation
temperature, their viscosities equalize, and the formulations are able to mix
with one another in
the manner described.
Process step (3)
After process step (2), oil production is continued in process step (3)
through at least one
production borehole. This can be done immediately thereafter, or else
optionally after a brief
pause, for example a pause of 1 to 3 days.
The oil can preferably be produced by customary methods, by injecting a
flooding medium
through at least one injection borehole into the deposit, and withdrawing
crude oil through at
least one production borehole. The flooding medium may especially be carbon
dioxide, water
and/or steam, preferably steam. The at least one injection borehole may be the
injection
boreholes already used for injection of formulations F1 and F2, or else other
injection boreholes
in a suitable arrangement.
However, it will be appreciated that oil production can also be continued by
means of other
methods known to those skilled in the art. For example, the flooding media
used may also be
viscous solutions of silicate-containing products or thickening polymers.
These may be synthetic
polymers, for example polyacrylamide or copolymers comprising acrylamide. In
addition, they
may be biopolymers, for example particular polysaccharides. In this case, the
viscosity of the
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aqueous flooding medium is adjusted to be higher than that of the last
injected formulation F1 or
F2.
It will be appreciated that it is possible, after process step (3), to once
again perform process
5 steps (2) and (3). This can be done at regular intervals, for example once
per year or - in the
case of steam flooding - as soon as a steam breakthrough is registered.
Advantages
The novel process for oil extraction has the following advantages compared to
known
technologies:
= It is possible to reduce the permeability of the highly permeable zones in
the carrier with
high temperature (90 -320 C).
= It is possible to operatively block the highly permeable channels in the
carrier in the
event of steam breakthrough, with brief interruption of steam flooding.
The novel process is inexpensive, does not need any new chemical products for
implementation, is based on the use of conventional technical means, and
allows an efficient
profile modification in carriers with high temperature and very high
temperature.
Other process variants
Process step (2) need not necessarily be executed after steam flooding. The
advantages of the
process are also manifested when the temperature at the injection borehole,
owing to natural
factors, is greater than 90 C, for example 90 C to 150 C, preferably 100 to
150 C. It is generally
possible to produce from such deposits by means of simple water flooding. If
the deposit
additionally has a comparatively low permeability, the injection rates are
correspondingly low for
a given pressure. In this case, the pumping of the conventional thermogels is
associated with
the risk that the injected formulations will gelate directly at the injection
boreholes owing to the
low flow rate, even at temperatures of 100 to 150 C. This can be avoided by
means of the
inventive process step (2), in which at least two different formulations F1
and F2 are injected.
Possible embodiments for process step (2) have already been described. It is
regularly
advisable in this embodiment to inject, after the injection of portions F1 and
F2, a portion of
water (volume approx. 2 to 3 times the total volume of F1 and F2).
In a further process variant, the process according to the invention can also
be used in the case
of cyclic steam injection and oil production (huff & puff method). The huff &
puff method
comprises three technological phases (steam flooding, wait, oil production),
which are
performed cyclically in succession. In a first phase, steam is injected into
the deposit. Owing to
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16
inhomogeneity of the deposit properties, the steam is distributed
inhomogeneously in the carrier
and can also lead into the surrounding rock when there is pronounced rock
fissuring. In order to
prevent this and to increase the efficiency of the steam injection, the first
phase is stopped after
the pumping of approx. 20 to 50% of the steam volume, and formulations F1 and
F2 are
pumped sequentially into the hot borehole. There may optionally be further
flooding with water.
Thereafter, the steam flooding is restarted and the remaining amount of steam
(50 to 80%) is
injected into the deposit.
The invention is illustrated in detail hereinafter by the working examples
which follow:
Laboratory tests - core flooding test
The process according to the invention was tested by means of a model test.
For this purpose,
loose deposit material from the oil-bearing stratum of a mineral oil deposit
in north-west
Germany was compressed in a tube. The permeability of the material was 1 to 12
darcies. The
filled tube was provided with devices for injection and withdrawal of liquids
at each end, and
heated to 200 C by means of a heater. As the first step, fresh water was
introduced into the
stratum and withdrawn at the other end, specifically in an amount of 3.9 times
the pore volume.
Thereafter, a formulation F2 was injected (solution of 40% by weight of urea
in water, amount
0.2 times the pore volume), then a portion of water (0.1 times the pore
volume), then a
formulation F1 (mixture of 30% by weight of an aqueous solution of
polyaluminum chloride
(Aln(OH)mCl3n-m, Al content 9.15% by weight, pH < 1, ALUSTAR 1010 L (from
Applied
Chemicals)) and 70% by weight of water, amount 0.2 times the pore volume),
then another
portion of water (0.2 times the pore volume) and another portion of
formulation F2 (0.2 times the
pore volume). After waiting for 18 hours at a constant temperature of 200 C,
water flooding was
continued.
The results of the test are shown in figure 2. Figure 2 shows the volume
injected and, as a
function thereof, the volume eluted (filtration rate) and the pressure
gradient. During water
flooding at the start, the pressure gradient is at first low. It rises
significantly from 0.073 bar/m to
from 43.6 to 53.9 bar/m only after formulations F1 and F2 have each been
injected fully. At the
same time, water production decreases significantly.
Employment of the process in an oil field
One example of a possible way of executing the process is explained below.
The deposit is a typical deposit containing viscous oil. A section of the
deposit has been
provided with an injection borehole and several production boreholes, and has
already been
flooded with steam for several months. The steam temperature is 280-320 C. In
some
production boreholes which communicate with the injection borehole, rapid
watering out of
production is being registered. The deposit is fissured as the result of
geological faults and has
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17
inhomogeneous permeability. Around the injection borehole, an extremely hot
zone with a
temperature of approx. 240 to 250 C and a radius of approx. 10 m has formed.
Steam flooding is stopped for a certain time. To cool and flush the borehole,
100 to 200 m3 of
water are first pumped at a temperature of 5 C.
In order to perform the profile modification and to block the highly permeable
zones in the oil-
bearing stratum, a first portion of formulation F2 (40% by weight of urea in
water) is prepared
above ground in a vessel. It is possible to use fresh water, salt water or
formation water. Using
customary equipment, 50 m3 of formulation F2 are injected into the deposit
through the injection
borehole. The first portion of formulation F2 has a low viscosity and flows
predominantly through
the highly permeable regions of the deposit.
Subsequently, 50 m3 of water are injected into the deposit. By virtue of the
injection of the 50 m3
of water, the first portion of formulation F2 is mobilized and forced from the
injection borehole
into the mineral oil deposit. The deposit temperature, which has fallen
briefly to approx. 200 C
as a result of injection of the water into the highly permeable "channels",
causes the
temperature of the injected formulation F2 also to rise. The viscosity of
formulation F2 rises
somewhat as a result of formation of gases (incipient decomposition of urea),
but no gel is
formed.
After the water, 50 m3 of a formulation F1 (30% by weight of aluminum(III)
chloride or
aluminum(III) nitrate) are injected through the injection borehole.
Subsequently, 50 m3 of water
are injected and, immediately thereafter, another 50 m3 of the abovementioned
formulation F2
are injected. The cycle described is repeated three times without
interruption: (50 m3 of water) -
(50 m3 of F2) - (50 m3 of water) - (50 m3 of F1). Thus, a total of 200 m3 of
F2 and 200 m3 of F1
are pumped in.
As a result of these measures, several banks of the formulation and of the
displacing water form
in the oil-bearing stratum.
On displacement of the formulation banks, there is retention (adsorption) of
urea and metal salt
on the rock, and secondly dilution, which leads to a reduction in
concentration of the active
ingredients in the banks.
As a result of the influence of the deposit temperature, the hydrolysis of the
urea to ammonia
and carbon dioxide also commences. The gases formed dissolve partly in the
water and
increase the pH of the water; they additionally form gas emulsions or foam-
like microstructures
with the water. This reduces the mobility of the first bank formed essentially
by the formulation
F2. The mobility of the first bank can also be reduced by supplying viscosity-
increasing
additives into the first portion of formulation F2.
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By virtue of the retention (adsorption) of urea in the oil-bearing stratum and
by virtue of the
reduced mobility of the urea-water solution, the portion of formulation F1
(aqueous solution of
the metal salt) injected thereafter catches up with the first bank, i.e. comes
into contact with
water with elevated pH. The mixing of the first and second banks in the oil-
bearing stratum
results, within a few minutes, in a gel bank in the highly permeable region of
the deposit. The
third bank - again composed of formulation F2 (urea solution) - ensures the
complete utilization
of the metal salt which has remained in rock pores as the result of retention
during the
displacement. The high concentration selected in the formulations guarantees
gel formation
even given multiple dilution of the formulations in the solid rock by the
formation water and flood
water. The compression and displacement of the third bank reduces the
permeability of further
highly permeable zones between the gel bank and the injection borehole.
By means of the volumes of the injected portions of formulations F1 and F2,
and of water, the
distance between the injection borehole and the gel bank can be controlled.
The injection pressure also rises with commencement of gelation. After
commencement of the
injection pressure rise, the water flooding is stopped for one to two days.
Thereafter, the water
flooding is restarted or steam flooding is continued. After the blockage of
highly permeable
regions, new flood paths form in wider regions of the oil-bearing stratum
under the influence of
the flooding medium, and further mineral oil is thus produced from the
formation.
