Note: Descriptions are shown in the official language in which they were submitted.
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Process for producing viscous mineral oil from underground deposits
Description
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 high-
permeability
regions of the mineral oil formation by injecting at least one formulation
into the deposit,
the formulation not being brought to a temperature at which the viscosity
increases
significantly until within the deposit, by injection of steam. The process can
be used
especially in the final stage of deposit development between water flooding
and 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 overlying
strata. 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 tim;
the formation may additionally also have regions with pores of greater
diameter and/or
natural fractures, however. In a mineral oil deposit, one or more oil-bearing
strata may
be present.
After the well has been sunk into the oil-bearing strata, the oil at first
flows to the
production wells 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 produce only 2 to 10% of the oil originally present in the deposit.
In the case
of higher-viscosity mineral 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 injection wells into the oil-
bearing strata.
This artificially increases the deposit pressure and forces the oil out of the
injection
wells to the production wells. 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 well
should force the oil homogeneously over the entire mineral oil formation to
the
production well. In practice, a mineral oil formation, however, has regions
with different
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= 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 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 well to the production well. The consequences of this are that the
oil-saturated
deposit regions with fine porosity and high flow resistance are no longer
flooded, and
that increasingly more water and less mineral oil is produced via the
production well. 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 in 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 high-permeability zones from the injection wells
to the
production wells, as a result of which the efficiency of the tertiary
production is reduced.
It is customary at present to conduct both steps when developing deposits
containing
viscous oil: water flooding followed by steam flooding. The blocking of the
high-
permeability channels during steam flooding is technologically difficult to
accomplish
due to the very high temperatures in the environment of the injection well.
The prior art discloses measures for closing such high-permeability zones
between
injection wells and production wells by means of suitable measures. As a
result of
these, high-permeability zones with low flow resistance are blocked and the
flooding
water or the flooding 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
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= conditions are known, for example, as "thermogels" or "delayed gelling
systems".
However, these formulations can be employed efficiently only for deposits
whose
temperature is above 60 C.
SU 1 654 554 Al discloses processes for producing oil, in which mixtures
comprising
aluminum chloride or aluminum nitrate, urea and water are injected into the
mineral oil
formations. At the elevated temperatures in the formation, the urea is
hydrolyzed to
carbon dioxide and ammonia. The ammonia which forms significantly increases
the pH
of the water, as a result of which high-viscosity aluminum hydroxide gel
precipitates
out, which blocks the high-permeability regions.
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 hydroxide chloride, and an activator which can release
bases
under formation conditions, for example urea, substituted ureas or
hexamethylenetetramine. The mixture is preferably used 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 describes a process for blocking high-permeability regions in
mineral
oil deposits, in which the volume of the high-permeability region to be
blocked is first of
all determined. Subsequently, an aqueous formulation comprising
carboxymethylcellulose and chromium acetate as a crosslinker is injected into
the
region to be blocked, the volume of the injected mixture being 15%, based on
the total
volume of the region to be blocked. In the next step, an aqueous formulation
comprising polyacrylamide and a crosslinker is injected.
RU 2 361 074 describes a process for blocking high-permeability regions in
mineral oil
deposits with high deposit temperature, in which formulations based on urea
and
aluminum salts are injected portionwise.
L. K. Altunina and V. A. Kushinov, Oil & Gas Science and Technology ¨ Rev.
IFP, Vol.
63 (2008), pages 37 to 48 describe various thermogels and the use thereof for
oil
production, including thermogels based on urea and aluminum salt, 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 interfacial tension. In one
variant, it is
possible simultaneously to close permeable regions of the mineral oil
formation, by, in
a second step, additionally injecting components such as acids which can form
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precipitates with the alkaline silicate solution.
US 4,300,634 describes a process for blocking highly permeable regions by
means of
foams. For this purpose, a foamable gel comprising water, a surfactant, a gel
former,
an aldehyde and a phenol compound is used. The gel is produced above ground in
a
tank by mixing the components and then pumped into the mineral oil deposit.
The gel
former prevents foam formation in the course of pumping. Subsequently, steam
is
injected into the mineral oil deposit in order to thermally decompose the gel
former. The
thermal decomposition of the gel former rapidly reduces the viscosity of the
gel, such
that it is possible to form a foam in which water forms the outer phase and
steam the
gas phase.
A disadvantage of the gel described in US 4,300,634 is that it only gets into
the zones
close to the injection well due to its high viscosity. A further disadvantage
is that foams
are relatively unstable and can collapse into themselves, such that the
process
described in US 4,300,634 achieves only time-limited blockage of highly
permeable
zones in the mineral oil deposit.
For formation of stable foams, a rest period normally has to be inserted after
the foam
formation. In the process of US 4,300,634, the foam is formed simultaneously
with the
hydrodynamic action of the flood wave on the injected gel. The hydrodynamic
action is
particularly strong especially in the zones close to the borehole, such that
the foams
are severely damaged especially in the zones close to the borehole.
RU 2 338 768 Cl describes a process for blocking permeable regions in mineral
oil
deposits, in which a solution comprising sodium phosphate, sodium oxalate,
sodium
carbonate and a mixture of carboxymethylcellulose and xanthan, and a second
solution
comprising calcium chloride, copper chloride and aluminum chloride, are each
injected
separately into the mineral oil formation, and the two formulations mix
underground. In
order to prevent premature mixing, it is also 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 calcium salts.
The time that the above-described gel-forming formulations require for
formation
thereof 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 50-120 C can take hours,
days or
even weeks, gel is of course formed considerably more rapidly at higher
temperatures.
For instance, according to L. K. Altunina and V. A. Kushinov, Oil & Gas
Science and
Technology ¨ Rev. IFP, Vol. 63 (2008), pages 37 to 48, gel formation of a gel-
forming
formulation comprising aluminum salts and urea sets in after 40 min at 150 C,
after
20 min at 200 C, and after 10 min at 250 C. When such formulations are
injected into a
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hot injection well or a hot formation, there is a high risk that gel formation
will set in
already in the immediate zone close by the injection well, since the flow rate
of the
formulation in the mineral oil formation is usually so low that the
formulations are heated
up very rapidly after the injection.
Thus, the injected formulations completely fail to reach the high-permeability
regions
that they are actually supposed to block, and the viscous gels are instead
already
formed at the injection well or in the zone close to the borehole. The high-
permeability
regions in the deposit may, however, extend for several hundreds of meters. In
the case
of use of the above-described thermogel formulations, only the permeability of
the zone
close to the borehole is thus reduced.
It is customary at present to conduct the development of deposits containing
viscous oil
(>30 cP) with the following steps: water flooding followed by steam flooding.
As
described above, the blocking of the high-permeability channels during steam
flooding
is technologically difficult to accomplish due to the very high temperatures
in the
environment of the injection well.
It was therefore an object of the present invention to provide a process for
producing
mineral oil from mineral oil formations, in which watering out of production
is reduced,
the level of oil recovery is controlled and the high-permeability channels in
the mineral
oil formation are reliably blocked during steam flooding.
This object is achieved by the following process for producing mineral oil
from an
underground mineral oil deposit into which at least one injection well and at
least one
production well have been sunk, comprising the following process steps:
(1) injecting at least one aqueous formulation F which exhibits an increase
in viscosity
at or above a critical temperature TK through the at least one injection well
into the
at least one oil-bearing stratum L, the critical temperature TK being above
the
temperature TL of the at least one oil-bearing stratum L,
(2) directly and/or indirectly heating at least a portion of the aqueous
formulation F
injected in step (1) by injecting steam into the mineral oil deposit,
(3) producing mineral oil through at least one production well,
the temperature of the aqueous formulation F on injection in step (1) being
below the
critical temperature TK thereof, and step (2) being conducted at least until
at least a
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5a
portion of the aqueous formulation F injected in step (1) has been heated to a
temperature of at least TK.
Another embodiment of the invention relates to a process for producing mineral
oil from
an underground mineral oil deposit comprising at least one oil-bearing stratum
L into
which at least one injection well and at least one production well have been
sunk, said
process comprising the following process steps:
(1) injecting at least one aqueous formulation F which exhibits an increase
in
viscosity at or above a critical temperature TK through the at least one
injection
well into the at least one oil-bearing stratum L, the critical temperature TK
being
above the temperature TL of the at least one oil-bearing stratum L,
(2) heating at least a portion of the aqueous formulation F injected in
step (1) by
injecting steam into the mineral oil deposit, wherein the at least one aqueous
formulation F when heated to the temperature Tk or higher forms a gel, and
(3) producing mineral oil through at least one production well,
the temperature of the aqueous formulation F on injection in step (1) being
below the
critical temperature TK thereof, and step (2) being conducted at least until
at least a
portion of the aqueous formulation F injected in step (1) has been heated to a
temperature of at least TK.
Another embodiment of the invention relates to the process defined
hereinabove,
wherein the heating is effected in step (2) by injection the steam into at
least one
stratum B in the mineral oil deposit which is in thermal contact with the at
least one oil
bearing stratum L.
In a preferred embodiment, the temperature TL of the oil-bearing stratum in
step (1) is 8
to 60 C.
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The process according to the invention has the advantage that deep penetration
of the
formulation into the high-permeability zones, even in deposits with low
temperature,
allows the profile modification of the flooding to be achieved in an efficient
manner. The
process enables blockage even of cooled (for example by water flooding) washed-
out
rock zones in the deposit. The distance between the borehole and the site at
which
blocking is to be effected can be regulated in the process according to the
invention.
This achieves efficient blocking of high-permeability zones, reduces watering
out of
production and increases the level of oil recovery.
The process according to the invention is especially suitable for use in the
development
of deposits containing viscous mineral oil after completion of water flooding
and before
commencement of steam flooding, since the formulation can be pumped deep into
the
high-permeability channels in the deposit cooled by water flooding, and only
thereafter
are these channels blocked in the course of steam flooding as a result of the
temperature-induced rise in viscosity.
Index of figures:
Figure 1 schematic illustration of the temperature profile between the
injection well
and production wells in a mineral oil deposit during steam flooding (vertical
section)
Figure 2 schematic illustration of the gelated zone in the deposit
(horizontal section)
Figures 3 schematic illustration of the gelated zone (two variants) in the
deposit
a and b between two wells (horizontal section)
Figure 4 schematic illustration of the temperature profile between the
injection well
and production wells in a mineral oil deposit during indirect heating of the
stratum flooded with formulation F (vertical section)
Figure 5 the same as in figure 4, except that the formulation F and the
heat carrier
are injected through different wells.
Reference numerals:
1: injection well
2: production well
3 high-permeability zone/region
4: deposit
5: temperature profile
6: formulation F in which the viscosity is increased ("gel bank")
7: oil-bearing stratum L
8: stratum B
9: non-oil-bearing intermediate stratum
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10: formulation F
11: steam
With regard to the invention, the following specific details can be given:
The process according to the invention for production of mineral oil is a
process for
secondary or tertiary mineral oil production, which means that it is employed
after
primary mineral oil production due to the autogenous pressure of the deposit
having
stopped and the pressure in the deposit has to be maintained by injecting
water and/or
steam. In the process, high-permeability regions in a mineral oil-bearing
stratum are
blocked.
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 15 to 25 API. The
oil
present in the mineral oil deposit preferably has a viscosity of at least 30
cP, more
preferably of at least 50 cP, measured at the temperature TL of the mineral
oil-bearing
stratum L in question in the deposit.
To execute the process, at least one production well and at least one
injection well are
sunk into at least one oil-bearing stratum of the mineral oil deposit. In
general, an oil-
bearing stratum is provided with several injection wells and with several
production
wells.
Process
According to the invention, the process comprises at least three process steps
(1), (2),
and (3), which are executed in this sequence, but not necessarily in immediate
succession. The process may of course comprise further process steps which can
be
executed before, during or after steps (1), (2), and (3).
The process according to the invention is preferably performed after the water
flooding.
This means that, before process step (1), water or else aqueous solution is
injected
into the at least one injection well, and mineral oil is withdrawn through at
least one
production well. "Aqueous solution" is understood in this case to mean
mixtures which
consist predominantly of water and one or more additives, such as water
thickeners or
surfactants. The term "mineral oil" in this context does not of course mean
single-phase
oil, but rather the customary emulsions which comprise oil and formation water
and are
produced from mineral oil deposits.
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The water injected or the aqueous formulation typically has a natural
temperature of 0
to 60 C, preferably of 5 to 30 C. The water temperature depends on the season
and on
the geographical location of the production region. If the deposit is warm and
deposit
water is used for water flooding, the temperature of the flooding water also
rises.
The injection of water or aqueous solution results in formation, in the region
between
the injection well and the production well, of a zone in which oil is
displaced by water.
The injection of water or aqueous solution allows the original deposit
temperature to be
altered, which means that it can be increased or decreased according to
whether the
water injected or the aqueous solution has a higher or lower temperature than
the
original temperature of the deposit.
The injection of water or aqueous solution increases the pressure in the
deposit, and
results in formation, in the region between the injection well and the
production well, of
zones ((3), see figures 1 to 5) in which oil is displaced by water or aqueous
solution.
These zones (3) are characterized by high or relatively high permeabilities.
These
zones (3) are also referred to as water-bearing "channels". In these channels,
the flow
resistance is reduced and the water injected flows through the channels from
the
injection well to the production well. This significantly reduces the
displacement effect
of the flooding water, watering out of production rises as a result, and oil
recovery from
the deposit is reduced. These adverse effects are particularly marked in the
case of
development of deposits containing viscous oil, since viscous oil is difficult
to mobilize.
High-permeability zones need not, however, be produced by the water flooding,
but
may also be present naturally in a formation. If the flooding water used is an
aqueous
solution comprising water thickeners or surfactants, the adverse effects
mentioned can
be reduced somewhat, but the flooding water will ultimately always find the
path of
least flow resistance between the injection well and the production well.
Therefore, in
the best case, after completion of water flooding, only 10 to 40% of the
mineral oil is
obtained.
When watering out of production rises relatively rapidly after commencement of
water
flooding, this is a clear indication of water breakthrough. In the case of
water
breakthrough, water flows through high-permeability zones from the injection
well to the
production well.
Process step (1)
Process step (1) can be employed as soon as watering out of production becomes
excessive or a so-called water breakthrough is registered. Process step (1)
can be
performed immediately after water flooding.
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To prepare for process step (1), it may be advantageous to measure the
temperature in
the region of the injection well and to determine the temperature range of the
mineral
oil-bearing stratum L in the region under the influence of flooding. Methods
for
determining the temperature range of a mineral oil deposit are known in
principle to
those skilled in the art. The temperature distribution is generally determined
by
temperature measurements at particular sites in the formation in combination
with
simulation calculations, the simulation calculations taking account of factors
including
amounts of heat introduced into the formation and the amounts of heat removed
from
the formation. Alternatively, each of the regions can also be characterized by
its
average temperature. It is clear to the person skilled in the art that the
outlined analysis
of the temperature range constitutes merely an approximation of the actual
conditions
in the formation.
Preferably in accordance with the invention, the mineral oil-bearing stratum L
in
process step (1) has a temperature of 8 to 60 C, preferably in the range from
8 to
50 C, measured at the injection well.
In the course of process step (1), in high-permeability zones of the mineral
oil deposit
in the region between at least one injection well and at least one production
well, at
least one aqueous formulation F which exhibits a viscosity increase at or
above a
critical temperature TK is injected through the at least one injection well
into the mineral
oil-bearing stratum L.
The increase in viscosity of the aqueous formulation proceeds above a critical
temperature TK, for example as a result of gel formation, flocculation or
sedimentation.
The aqueous formulation comprises, as well as water, one or more different
chemical
components which, on attainment of the critical temperature TK, lead to an
increase in
viscosity. Typically, the aqueous formulation comprises at least two different
components. These may be either inorganic or organic components, or else
combinations of inorganic and organic components.
Preferably in accordance with the invention, the formulation F used is a
formulation
which forms a gel at the temperature TK or higher.
Suitable formulations are known to those skilled in the art, for example
formulations
based on water-soluble polymers as in US 4,844,168, US 6,838,417 B2, or
US 2008/0035344 Al. Formulations essentially based on inorganic components are
described, for example, in SU 1 654 554 Al, US 4,889,563, RU 2066743 Cl,
WO 2007/135617, US 7,273,101 B2 or RU 2 339 803 C2. Suitable formulations are
also commercially available.
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In a preferred embodiment, the at least one aqueous formulation F comprises at
least
one compound M selected from metal compounds and semimetal compounds which
can form gels when admixed with base, and at least one water-soluble activator
which
brings about an increase in the pH of the aqueous formulation at a temperature
of at
5 least TK.
Preferably in accordance with the invention, the at least one compound M is
selected
from water-soluble aluminum(III) salts, colloidal Si compounds and mixtures
thereof
which can form gels when admixed with base. As a variant, it is also possible
to use
10 mixtures based on organic products (e.g. cellulose ethers). More
preferably, the at
least one compound M is selected from aluminum chloride, aluminum nitrate,
aluminum
acetate, aluminum acetylacetonate, aluminum sulfate, partial hydrolysates
thereof,
colloidal SiO2 and mixtures thereof. Partial hydrolysates of aluminum salts
are partially
hydrolyzed aluminum salts, for example aluminum hydroxychloride. The pH of
formulation F is generally 5 5, preferably 5 4.
The colloidal Si compounds are preferably colloidal SiO2, which should
advantageously
have an average particle size of 4 nm to 300 nm. The specific surface area of
the SiO2
may, for example, be 100 to 300 m2/g.
Useful water-soluble activators include all compounds which release bases or
bind
acids when heated to a particular temperature in aqueous medium, and thus
ensure an
increase in the pH of the solution/formulation. The water-soluble activators
used may,
for example, be urea, substituted urea such as N,IV-dimethylurea,
hexamethylenetetramine, cyanates and mixtures thereof. Urea, for example, is
hydrolyzed in aqueous medium to give ammonia and CO2.
More preferably, the aqueous solution F comprises at least one compound
selected
from aluminum chloride, aluminum nitrate, aluminum acetate, aluminum
acetylacetonate, aluminum sulfate, partial hydrolysates thereof and mixtures
thereof,
and at least one water-soluble activator selected from urea, substituted urea,
hexamethylenetetramine, cyanates and mixtures thereof.
The increase in the pH results in formation of high-viscosity, water-insoluble
gels which
comprise metal ions, hydroxide ions and possibly also further components. In
the case
of use of aluminum compounds, aluminum hydroxide or aluminum oxide hydrate gel
can form, which may of course also comprise further components, for example
the
anions of the aluminum salt used.
As well as water, the formulation F may optionally also comprise further water-
miscible
organic solvents. Examples of such solvents comprise alcohols. In general, the
formulation F should comprise at least 80% by weight of water, based on the
sum of all
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solvents in the formulation F, preferably at least 90% by weight and more
preferably at
least 95% by weight. Most preferably, the only solvent used is water.
The concentration of the metal compounds used is selected by the person
skilled in the
art such that a gel with the desired viscosity forms. For this purpose, the at
least one
water-soluble activator is used in such a concentration that a sufficient
amount of base
can form to lower the pH to such an extent that a gel can indeed precipitate
out. In
addition, the gel formation time t -Gel can also be determined via the amounts
or the
ratios. The higher the concentration of the activator, the greater - for a
given
concentration of the metal compound - the rate of gel formation. This
relationship can
be used by the person skilled in the art to accelerate or to slow the gel
formation time in
a controlled manner. The rate of gel formation after the critical temperature
TK has
been exceeded is naturally also determined by the temperature which exists in
the
mineral oil deposit. In the case of aluminum salts, an amount of 0.2 to 3% by
weight of
aluminum (III), based on the aqueous formulation, has been found to be
advantageous.
The amount of the at least one water-soluble activator should at least be such
that
3 mol of base are released per mole of AI(III).
For example, an inorganic mixture of 8% by weight of AlC13 (calculated as
anhydrous
product, this corresponds to 1.6% by weight of AI(III)), 25% by weight of urea
and 67%
by weight of water is used. The maximum concentrations of the components are
selected with consideration of the dilution of the mixture in the geological
layer,
specifically 17% by weight of AlC13, 34% by weight of urea, the remainder
being water.
At these concentrations, even in the case of 8-fold dilution of the mixture,
the formation
of the gel when the temperature rises is guaranteed. In the case of injection
of the
formulation into the geological layer, the intensive dilution takes place
predominantly at
the edge of the flooded zone. This preserves the ability of the formulation to
form a gel
when the temperature rises. Since the above-described inorganic mixture is a
true
solution, sedimentation, formation of flocs or gelation in the geological
layer before the
temperature rises is ruled out. The inorganic aqueous solution based on urea
and
aluminum salt can be stored for months without any change in its properties.
The inventive formulation F is not a gel below the critical temperature TK.
Only at or
above the critical temperature TK does the formulation F develop the
properties of a
gel.
A gel in relation to the formulation F is understood in the present context to
mean that
the formulation F after gelation under the deposit conditions has a much
higher
viscosity than prior to gelation, preferably in the range from 200 to 5000 cP,
preferably
in the range from 400 to 3000 cP and especially in the range from 500 to 2000
cP. The
viscosity is measured at shear rates in the range from 0.5 to 1.5 s-1 under
the deposit
conditions. The formulation F in gelated form generally has a flow limit.
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In the ungelated state, the inventive formulation F is not a gel. This is
understood to
mean that, prior to the gelation, it has a much lower viscosity than after the
gelation,
preferably in the range from 5 to 100 cP, more preferably in the range from 7
to 70 cP
and especially in the range from 10 to 50 cP. In the ungelated state, the
formulation F
generally does not have a flow limit or a flow limit which is well below that
in the gelated
state.
This has the advantage that the formulation F can be injected deep into highly
permeable zones prior to gelation, and the highly permeable zones are
effectively
blocked after the gelation.
In a preferred embodiment, the first portion injected in the course of pumping
of the
aqueous formulation F is the formulation F with maximum possible component
concentration. Thereafter, the component concentration can be reduced in
stages or
continuously. This guarantees the gelation of the formation F even if dilution
takes
place underground. If, for example, the formulation F based on urea and
aluminum salt
is injected with maximum component concentration, 8-fold dilution with water
is allowed
without impairment of the gel properties.
Tab. 1 below gives an illustration of the time until gel formation for a
mixture of 8% by
weight of aluminum chloride (calculated as anhydrous product, corresponds to
1.6% by
weight of AI(III)), 25% by weight of urea and 67% by weight of water.
Tab. 1
Temperature 100 90 80 70 60
[ C]
Gel formation 1/4 1 3 6 30
time [days]
The formulations F may additionally comprise further components which can
accelerate
or slow gel formation. Examples thereof comprise further salts or naphthenic
acids. In
addition, the formulations F may also comprise surfactants and/or thickeners,
for
example thickening polymers. The thickening polymers added may, for example,
be
polyacrylamide, xanthan or other biopolymers based on polysaccharide.
Typically, a
sufficient amount of thickener is added to the formulation F that the
viscosity of the
formulation is raised slightly, for example up to 20 to 40 cP. This does not
disrupt
pumping of the formulation into the deposit. The thickener reduces the volume
of
formulation required, since the viscous formulation penetrates predominantly
into the
high-permeability regions/channels (3) and is effectively "deposited" there.
The
thickening of the injected formulation also significantly reduces the dilution
thereof in
the geological layer, since the miscibility of the media with different
viscosity is less
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than for media with the same viscosity, and the stratum water from the high-
permeability zones is displaced by the viscous mass.
The above-described preferred formulations F comprising at least one compound
M
selected from metal compounds and semimetal compounds which can form gels when
admixed with bases, and at least one water-soluble activator, have the
advantage that
inorganic gels are formed. These gels form at approx. 70 C and are stable up
to
temperatures of 300 C, and are therefore particularly suitable for deposits
with very
high temperatures, for example deposits at the end of steam flooding. In
addition, the
inorganic gels can, if required, also be removed very readily from the
formation, by
injecting acid into the formation and dissolving the gels.
The critical temperature TK of the above-described preferred formulations F
comprising
at least one compound M selected from metal compounds and semimetal compounds
which can form gels when admixed with bases, and at least one water-soluble
activator, is the gel formation temperature of the particular inorganic
component. In
these formulations, TK is 60 to 70 C. These formulations are therefore of good
suitability for use after completion of water flooding and before commencement
of
steam flooding.
Process step (1) can be performed directly before commencement of steam
flooding
(process step (2)), but it can also be performed a certain time before
commencement
of process step (2). For example, the aqueous formulations F used with
preference,
comprising at least one compound M selected from metal compounds and semimetal
compounds which can form gels when admixed with base, and at least one water-
soluble activator which brings about an increase in the pH of the aqueous
formulation
at a temperature of at least TK, are what are called true solutions and may be
present
for months in the deposit without losing activity. This means that, even after
storage for
months in the deposit, they exhibit an increase in viscosity in the event of
an increase
to a temperature of at least TK.
In process step (1), at least one aqueous formulation F is injected into at
least one
injection well. However, it is also possible to inject more than one aqueous
formulation
F; for example, it is possible to successively inject portions of two or more
different
aqueous formulations. The first formulation injected may, for example, be an
inexpensive solution of an organic thermogel based on cellulose ethers. The
formulation forms a gel at temperatures of 70 to 80 C and remains stable
underground
up to temperatures of 180 to 200 C. The second formulation used may be one of
the
above-described aqueous formulations F which comprises at least one compound
selected from metals and semimetals and at least one water-soluble activator
(especially urea). These formulations are active at temperatures of 60 to 70 C
and
remain stable underground up to temperatures of 280 to 300 C.
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If the distance between the at least one injection well and the at least one
production
well is relatively high, in order to reduce the costs, it is possible for only
one third or half
of the total length of the channels present between the injection well and the
production
well to be filled with the aqueous formulation. In most cases, this is
sufficient to conduct
efficient profile modification.
The amount of formulation F is determined after geological analysis of the
deposit
section. In most cases, the amount of formulation F is defined by calculating
the limit of
economic viability of the measures. If the water breakthroughs are determined
predominantly by the geological faults and the distance between injection well
and
production wells is small, the requirement for aqueous formulation F is
relatively low.
Since geophysical studies can discover only some of the faults, the
calculations of the
volume of formulation F needed are very uncertain. The best method in this
case is the
identification of the output of the formulation F in the adjacent wells by
chemical
analysis of the wet oil. The pumping of formulation F is stopped after the
identification
of the formulation F in the adjacent wells. The estimated amount of
formulation F for
the abovementioned deposit is approx. 100 to 200 m3 per meter of thickness of
the oil-
bearing stratum.
When the high-permeability regions in the mineral oil deposit are in the form,
for
example, of strata (the permeability of the matrix is not homogeneous), the
requirement
for aqueous formulation F is much greater. In this case, only some of the high-
permeability zones are saturated with formulation F. The economic factors come
into
.. play here. For efficient performance of the process, the volume of the
injected
formulation F (estimate) should be at least 10% of the estimated pore volume
(based
on the high-permeability regions/layers) in the mineral oil deposit between
injection well
and production well, preferably at least 20%, more preferably at least 30%.
The same purpose is served by a variant of the present process in which the
injection
of the aqueous formulation is followed directly by subsequent flooding with
water. The
subsequent flooding with water shifts the front comprising the aqueous
formulation in
the direction of the middle of the high-permeability regions. In the course of
steam
flooding, the high-viscosity region then forms in the middle region of the
high-
permeability channels. This variant of the process according to the invention
is shown
schematically in figure 3a.
While the aqueous formulation F is injected into at least one injection well,
mineral oil
can be withdrawn from at least one production well. In a preferred embodiment,
mineral oil is withdrawn from the at least one production well during process
step (1),
and process step (2) is commenced as soon as aqueous formulation F injected
through
the at least one injection well is detected in the mineral oil withdrawn.
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In a further variant of the present process, mineral oil is withdrawn from at
least one
production well during process step (1), and no mineral oil is withdrawn from
this
production well for a period as soon as aqueous formulation F injected through
the at
5 least one injection well is detected in the mineral oil withdrawn.
Preference is given to
not withdrawing any mineral oil until process step (2) is commenced.
Process step (2)
10 After process step (1), at least a portion of the aqueous solution
injected is heated in
process step (2) directly (variant 1) and/or indirectly (variant 2) by
injection of steam
into the mineral oil deposit. The steam used preferably has a temperature of
200 to
350 C. The injection of steam into an injection well is known to those skilled
in the art,
as is the equipment suitable therefor. This step is also known by the term
"steam
15 flooding". Steam flooding can be performed with the conventional
technology known to
those skilled in the art.
Variant 1
.. In the case of direct heating, the steam is injected directly into the
mineral oil-bearing
stratum L, into which the aqueous formulation F has been injected in step (1)
(variant
1). In a preferred embodiment, steam is injected for this purpose through the
at least
one injection well into the at least one oil-bearing stratum.
The steam is converted relatively rapidly to steam condensate in the deposit.
The
region in which the condensation takes place is typically within a radius from
5 to 40 m
from the injection well. The hot steam/steam condensate attempts to flow to
the
production well through the high-permeability channels which were created at
the
earlier stage of water flooding or already existed beforehand. These channels,
however, have been filled with the aqueous formulation F in process step (1).
The
formulation is shifted by the steam/steam condensate in the direction of the
production
well. Under the action of the hot steam/steam condensate, the temperature in
the oil-
bearing stratum L and in the deposit rises. The aqueous formulation is
likewise heated
until, on attainment of the critical temperature Tic, the viscosity of the
formulation F rises
significantly, for example as a result of formation of a high-viscosity gel.
The longer the
oil-bearing stratum L is flooded with the steam, the greater will be the
volume in the oil-
bearing stratum L which has been filled with the formulation F and in which
the
viscosity increase has taken place. The high-permeability channels are thus
"blocked".
The further injected hot steam and the hot steam condensate which forms then
flow
.. into the regions from which oil had not been recovered in the preceding
mineral oil
production, for example in the course of water flooding.
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A schematic illustration of the temperature profile (5) and of a vertical
section through a
mineral oil-bearing stratum in a deposit after commencement of steam flooding
is
shown in figure 1. In the region of the high-permeability channels (3) in
which the
temperature TL of the mineral oil-bearing stratum is above the critical
temperature TK of
the formulation, a viscosity increase has taken place, for example as a result
of
formation of a gel; see region (6). figure 2 shows a horizontal section
through the
mineral oil-bearing stratum L in the mineral oil deposit, in which the
distribution of the
region (6) in which the viscosity has increased, of the high-permeability
channels (3),
and the injection well (1) and several production wells (2) are shown.
Another option in this variant is, after heating the deposit zones saturated
with
formulation to the critical temperature TK, to switch from steam flooding back
to water
flooding. In the case of this option, steam flooding is used only to conduct
the increase
in viscosity of the formulation. This option can be used especially in
development of
deposits with oil viscosity from approx. 20 to 50 cP.
A further option in this variant is to inject heat carrier (steam/steam
condensate) and
formulation F simultaneously into at least two different wells. In the case of
this option,
heat carrier and formulation F move toward one another in the deposit.
Variant 2
In the case of indirect heating of at least a portion of the injected aqueous
formulation
F, the steam is injected into at least one further stratum B which is in
thermal contact
with the mineral oil-bearing stratum L. Stratum B is preferably likewise a
mineral oil-
bearing stratum which may comprise the same type or quality of mineral oil as
stratum
L, but also mineral oil of other types or qualities. "In thermal contact" in
the present
context means, in relation to strata L and B, that heat can be transferred
between
them. At the same time, they are sufficiently close to one another that, on
injection of
steam into stratum B, an amount of heat is transferred to stratum L which is
sufficient to
heat at least a portion of the aqueous formulation F injected into stratum L
to at least
TK.
Process variant 2 is preferably employed in an oil deposit which comprises at
least two
oil-bearing strata in thermal contact with one another. In such a case, the
oil-bearing
strata often have different properties. This relates, for example, to
permeability,
porosity and oil viscosity, stratum pressure. Due to these different
properties,
simultaneous recovery of oil from several strata is often complicated or
impossible.
Figure 4 shows a schematic of such a deposit with two oil-bearing strata.
Stratum 7 has
a relatively high permeability and is saturated with oil which can be produced
by water
flooding. This stratum (7) is the first to be developed by flooding it with
water. Since the
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permeability of stratum (7) is inhomogeneous, water breakthroughs are
registered in
the production wells (2) after a certain time. Due to the rapid rise in
watering out of
production, the decision is taken to stop production from stratum (7) for a
certain time.
Before oil production from stratum (7) is stopped, this stratum is flooded
with aqueous
formulation F. As a result, the high-permeability channels which enable the
water
breakthroughs in stratum (7) are filled with the formulation F. The critical
temperature
TK of the aqueous formulation F is above the temperature TL of stratum (7).
Thereafter, the lower oil-bearing stratum (8) is developed by steam flooding.
In this
stratum is viscous oil which can be produced efficiently from this stratum
only by steam
flooding. In the course of steam flooding of stratum (8), not only is stratum
(8) heated,
but also the non-oil-bearing intermediate stratum (9) and the adjoining
stratum (7).
When the temperature in stratum (7) rises up to temperature TK, the increase
in
viscosity of formulation F commences, and the high-permeability zones are
partly or
completely filled with viscous formulation. After the increase in viscosity is
complete,
water flooding of stratum 7 continues.
The intermediate stratum (9) may be 1 to 5 meters in thickness. In the case of
injection
of 300 to 600 tonnes of steam per day at a temperature of approx. 300 C, the
temperature of stratum (7) reaches the temperature TK within a couple of
months. In
order to accelerate the increase in viscosity, an aqueous formulation F with
low critical
temperature can be used to reduce the difference between temperature TK and
temperature TL of stratum 7.
The aqueous formulations F used may be inorganic and organic compositions
whose
temperature TK can be regulated. For example, the known inorganic mixtures
based on
urea, aluminum salt and urotropin, or the organic mixtures based on
methylcellulose
and urea, are useful.
Variant 2 can be performed according to the following schemes:
Scheme 1: water flooding of stratum L
subsequent flooding of stratum L with
aqueous formulation F (after an increase in watering out of production)
adjustment
of flooding of stratum L and subsequent steam flooding of adjacent stratum B
recommencement of water flooding of stratum L after the temperature of this
stratum
has increased to at least TK.
Scheme 2: water flooding of stratum L ¨> subsequent flooding of stratum L
(after
watering out of production has increased) with aqueous formulation F and
simultaneous steam flooding of adjacent stratum B recommencement of water
flooding of stratum L after the temperature of this stratum has increased to
at least TK.
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According to scheme 2, the filling of the high-permeability zones with aqueous
formulation F is performed simultaneously with steam flooding of the adjacent
stratum.
Since the thermal transfer from the steam-flooded stratum to the water-flooded
stratum
is slow, scheme 2 is easy to implement.
Scheme 3 (figure 5): water flooding of stratum L ¨+ subsequent flooding of
stratum L
(after watering out of production has increased) with aqueous formulation F
and
simultaneous or non-simultaneous steam flooding of adjacent stratum B through
another well recommencement of water flooding of stratum L after the
temperature
of this stratum has increased to at least TK.
When the difference between TL (temperature of stratum 3) and TK is relatively
large,
the temperature rise of layer 3 is controlled/measured during the steam
flooding of
stratum 8 (figures 4, 5), and the pumping of formulation F into stratum 3 is
not
commenced until there is a temperature difference (TK - TL) of 1 to 5 C.
After the flooding of stratum 7 has been stopped, the movement of the injected
liquids
(aqueous formulation F and any water used for subsequent flooding) is minimal
and the
"washout" of the aqueous formulation F is ruled out. The aqueous formulation F
is
stored in the solid rock. The properties of the aqueous formulation F are
preserved
unchanged for several months. The aforementioned inorganic formulations are
what
are called true solutions and do not have a tendency to form sediments or to
flocculate.
In a further embodiment, steam is injected before process step (3) into those
production wells where aqueous formulation F injected through the at least one
injection well is detected in the mineral oil withdrawn therefrom. In this
way, in the
region close to the particular production well, a profile modification is
likewise
performed and the high-permeability channels are closed. This embodiment of
the
process according to the invention is shown schematically in figure 3b. The
steam
injected into the production wells preferably has a temperature of 200 to 350
C. This
measure can be performed by the process according to the invention either by
variant
(1) or by variant (2).
Step (2) of the process according to the invention is performed until at least
a portion of
the aqueous formulation F injected has been heated to at least TK, such that
an
increase in viscosity, for example as a result of gel formation, has taken
place in at
least some of the injected formulation F, and the high-permeability channels
are
blocked as a result at least to such an extent that, on continuation of
mineral oil
production, there is a rise in the amount of mineral oil produced or a
reduction in
watering out of production. According to the embodiment, this may last for a
shorter or
longer period. If step (2) is performed, for example, according to variant
(1), which
means that steam is injected directly into the mineral oil-bearing stratum L,
the viscosity
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increase is usually much more rapid in the area close to the well (radius 3-5
meters),
for example occurs within a few days, for example within 1 to 3 days. If step
(2) is
performed according to variant (2), more time is typically required until the
temperature
TK required for the viscosity increase has been attained. According to the
distance
between the strata L and B in question, this may also take a few months, for
example 4
to 6 months. This is not a problem particularly when true solutions such as
the above-
described aqueous formulations F comprising at least one compound M and at
least
one water-soluble activator are used in step (1), since these formulations,
being true
solutions, are stable against flocculation and sedimentation, and do not lose
their
characteristic of exhibiting an increase in viscosity when heated to at least
TK even
after a few months of storage in the deposit.
In principle, step (2), in accordance with the invention, can be performed
according to
variant (1) or variant (2); it is also possible to conduct the respective
measures of the
two variants simultaneously or in succession, which means that steam can be
injected
in step (2) both into the mineral oil-bearing stratum L and into one or more
further strata
B which may be present. This can be effected simultaneously or in alternating
succession.
Injection of the at least one aqueous formulation F may optionally be followed
by
subsequent flooding with water, for example in order to shift the aqueous
formulation
deeper into the mineral oil-bearing stratum L.
Process step (3)
In process step (3), the production of mineral oil is continued through at
least one
production well. The oil can be produced by customary methods, by injecting a
flooding
medium through at least one injection well into the mineral oil deposit and
withdrawing
crude oil through at least one production well. The flooding medium may
especially be
carbon dioxide, gas-water mixture, water, thickened water and/or steam. The at
least
one injection well may be the injection wells already used for injection of
formulation F
in process step (1) and of the steam in process step (2), or else other
injection wells in
suitable arrangement.
The oil can, however, of course also be produced 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 acrylamide-comprising
copolymers.
In addition, they may also be biopolymers, for example particular
polysaccharides.
The present invention is described hereinafter with reference to examples.
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= Employment of the process in an oil field
One example of a possible method of conduction is described hereinafter.
5 The deposit is a typical mineral oil deposit containing viscous oil (150
to 190 cP before
commencement of mineral oil production). A section of the deposit is provided
with one
injection well and several production wells and has already been flooded with
water for
several years. The natural deposit temperature is 37 C. According to
estimates, the
deposit temperature after the water flooding has fallen to 20 to 25 C (at
least in the
10 zones which have been "washed through" efficiently). The vertical and
horizontal
permeability have marked anisotropy. The deposit has numerous geological
faults.
Most of the geological faults are water-bearing. In the water-flooded deposit
section,
the level of oil recovery is 20%. Watering out of production has reached 94%,
which
means that 94% of the liquid produced is water. The communication, i.e. the
flow of the
15 injected flooding medium between injection wells and production wells,
takes place
predominantly via the geological faults, and an oil-bearing stratum with
extremely high
permeability and low thickness.
A decision is made to continue treatment of the deposit by steam flooding.
In a mathematical simulation, it is found that the volume of the high-
permeability
regions in a radius of 50 m from the injection well is approx. 12 000 m3
(hypothetical
pore volume/empty space). Blockage of the high-permeability regions/channels
in a
radius of 50 m around the injection well is sufficient to conduct effective
profile
modification for the subsequent steam flooding.
Directly before commencement of the steam flooding, about 3000 m3 of aqueous
formulation of the following composition are injected into the deposit through
the
injection well:
30% by weight of urea,
18% by weight of aluminum hydroxychloride,
0.5% by weight of polyacrylamide and
51.5% by weight of water.
The concentration figures are based on the total weight of the formulation.
In the course of injection and flooding of the formulation in the deposit, it
is diluted by
the water present in the deposit by about four times in a radius of 50 m
around the
injection well; the potential gel volume is thus about 12 000 m'. In the
course of dilution
of the formulation with water and the subsequent gel formation of the
formulation in the
course of steam flooding, the gel maintains the desired rheological
properties. Only in
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the case of dilution by about eight times does the formulation lose the
desired
rheological properties and hence its ability to modify the profile.
Thereafter, 500 m3 of
water are injected. The polyacrylamide serves to thicken the formulation F. As
a result
of addition of polyacrylamide, the viscosity of the formation (before
gelation) reaches
10 ¨ 40 cP. The low-viscosity mass flows predominantly through the faults and
through
the high-permeability thin layer.
Subsequently, flooding with hot steam is commenced. The steam temperature is
280 to
320 C. By virtue of its high mobility, the steam spreads relatively rapidly in
the deposit
and condenses with release of heat of condensation. The temperature in the
zone
close to the injection well exceeds the critical temperature TK after about 3
to 5 days. TK
in this case is the gel formation temperature of the aqueous formulation
injected, which
is 60 to 70 C. The aqueous formulation injected is converted to the gel. Even
though
the rock in the deposit is yet to attain the critical temperature TK, the hot
steam
condensate mixes with the aqueous formulation, as a result of which the
temperature
of the formulation rises and a gel forms, which partly or fully blocks the
pores and
cracks in the rock. The viscosity of the gel which forms reaches 500 to 1500
cP. As a
result, the steam and the hot steam condensate are diverted into the zones of
the
deposit from which oil has been recovered only to a minor degree in the course
of
water flooding. As steam flooding continues, the temperature front migrates
from the
injection well in the direction of the production well. At the same time, the
gel volume in
the deposit grows. The consequence is a rise in the oil production rates and
the level of
oil recovery from the deposit, and a fall in watering out of production.
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