Note: Descriptions are shown in the official language in which they were submitted.
1
METHOD OF DEVELOPMENT OF A DEPOSIT OF HIGH - VISCOSITY
OIL OR BITUMEN
The invention relates to the petroleum industry, namely to the methods for
developing
heavy oil reservoirs using horizontal wells and thermal oil recovery.
Patent RU 2095549 discloses a method of developing heterogeneous oil
reservoir,
which comprises an alternation of a period of injection of water in the
reservoir through an
injection well and a simultaneous reservoir fluids extraction through
production wells and the
period of extraction of the reservoir fluids through the production wells when
water is not
injected through the injection well. Periodically, once in 2-3 days, produced
water is analyzed
to determine its mineralization. The injection of water with simultaneous
production of the
reservoir fluids is carried out to achieve a stable value of the produced
water mineralization.
The disadvantages of this method are the high material costs associated with
the need
to build technological well with two wellheads, the lack of consideration of
the initial
properties of the produced fluids allowing reaching the highest oil recovery
factor, as well as
analyzing produced fluids in remote from production locations specialized
laboratories, which
reduces the reliability of the results.
A method for the development of deposits of heavy oil according to patent RU
2379494 is the closest analog to the present invention. The said method uses a
pair of
horizontal injection and production wells, horizontal sections of which are
arranged in parallel
one above :the other in a vertical plane of a producing reservoir. The wells
are provided with
tubing strings that allow simultaneous downloading of a beat-transfer agent
and extracting the
fluids, download the heat carrier, heating producing reservoir creating a
steam chamber,
extracting the fluids by the downhole pumps through the production well
through the tubing
strings, and controlling technological parameters of the reservoir and the
well. The ends of the
tubing strings are placed on opposite ends of the horizontal section of the
wells. Heating of the
producing reservoir starts with steam injection through both wells, heating
inter-well reservoir
area, reducing the viscosity of heavy oil, and the steam chamber is created by
pumping the
heat-transfer agent propagating to the top of the producing reservoir with an
increase of the
steam chamber dimensions. During the extraction of the fluids from time to
time (2-3 times a
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week) mineralization of the produced water is defined, the impact of changes
in the produced
water mineralization on the steam chamber heating uniformity is determined,
and taking into
account the changes in produced water mineralization adjust uniformity of the
steam chamber
heating by controlling the heat carrier injection mode or extraction rate of
the production well
,
to achieve stable value of mineralization of the produced water.
The disadvantages of this method are the lack of consideration of the initial
properties
of the produced products allowing to reach the highest oil recovery, the
implementation of the
analysis of produced products in specialized labs, remote from the sampling
point, which is
produced with large periods (1 every 2-3 days), which reduces the reliability
of the results.
The object of the invention is to provide a method, which allows increasing
the oil
production rate and recovery factor by taking into account the properties of
produced fluids,
increasing the number of produced water mineralization measurements carried
out directly at
the well.
This object is achieved by a method of developing deposits of heavy oil or
bitumen
using a pair of horizontal injection and production wells, horizontal sections
of which are
arranged in parallel one above the other in a producing reservoir equipped
with a tubing string
allowing simultaneous injection of a heat-transfer agent and extraction of the
product. The
method also comprises pumping a heat transfer fluid, heating the producing
reservoir with the
creation of a steam chamber, extracting the product by the downhole pumps
through the lower
production well tubing strings, the ends of which arc located on opposite ends
of the
horizontal section of the well. The mineralization of the produced water is
determined, the
dependence of the uniformity of the steam chamber heating from the
mineralization is
determined, and the injection mode of the heat transfer agent and/or the
product extraction
mode is adjusted to achieve a stable value of mineralization of the produced
water ensuring
uniform heating of the steam chamber.
According to the invention, before the start of the field development in the
appraisal
well, or during drilling of the production and injection wells, cores of the
producing reservoir
arc obtained. The said cores are used for determining water mineralization and
composition of
the dissolved solids. The optimum produced water mineralization is
corresponded to the
. . .. .
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minimum steam-oil ratio and determined for obtaining the maximum oil recovery
factor. After
the reservoir is heated and the steam chamber is created, the produced water
mineralization is
determined at least once a day using measuring tools directly in the flow of
produced fluids.
After reaching a stable value of produced water mineralization, the heat-
transfer agent
injection through the injection well and fluid extraction from the production
well are adjusted
so that the water mineralization approaches optimum level.
Preferably, the measuring devices are located on a substrate of a hydrophilic
material.
They are placed at the inlet of the downhole pumps and functionally linked to
the appropriate
-pumps to 'adjust the product extraction and maintain the lowest possible
pressure which is
eliminated the gas phase release at the pump intake.
Tle invention is illustrated by the following drawings:
Fig. 1 shows the layout of the wells with one wellhead each;
Fig. 2 shows the layout of the wells with double wellheads;
Fig. 3 is a graph of the coefficient of oil displacement (C(dis) due to
mineralization (M)
of produced water at Ashalchinskoye field at a temperature of 100 C.
Method of developing deposits of heavy oil or bitumen is implemented as
follows.
Before the oil field development in the appraisal well (not shown) or during
the
drilling production and injection wells 1 and 2 (Figs. 1 and 2) with the
horizontal portions 3
and 4 a core of a production reservoir 5 is obtained for the study of the
reservoir fluids
including water mineralization and composition of dissolved solids. Based on
these data, the
optimal mineralization of the produced water is determined experimentally in
the process of
production to obtain the maximum oil recovery factor (CUR) for the reservoir
5. The pair of
' -injectiOn and production wells (Figs. I and 2) is drilled so that their
horizontal portions 3 and
4 are arranged in the reservoir 5 in parallel one above the other. The wells I
and 2 can have
two wellheads as shown in Fig. I or one wellhead as shown in Fig. 2.
Furthermore, due to
individual characteristics of the producing formation, one of the wells may
have two
wellheads and another one wellhead (not shown in the figures). The wells 1 and
2 are
equipped with two corresponding tubing strings 6, 7 and 8, 9.
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Instead of tubing strings, the wells 1 and 2 can be fitted with a coil tubing.
The
producing wells 2 along the length of its horizontal section 4 can be provided
with sensors 10
for additional temperature control. The tubing strings 6 and 7 make it
possible to conduct heat
transfer agent injection (for example, steam), and tubing strings 8 and 9 to
carry out the
simultaneous extraction of products with corresponding downhole pumps ii and
12. The
reservoir 5 is heated by the steam creating a steam chamber (not shown) above
the horizontal
part 4 of the production well 2. Due to convective and conductive heat
transfer at the stage of
development of steam injection in both wells I and 2, the inter-well reservoir
zone (zone
between the producing well 2 and injecting well 1) is heated reducing the
viscosity of the
heavy oil. In addition to, oil thermally expands, and, finally, its mobility
increases. Then in
the process of heavy oil production in the injection well I steam is injected,
which is due to
the difference in density tends to move to the top of the productive reservoir
5 causing a
growth of the steam chamber. On the water-oil interface of the steam chamber
and the cold oil
and water saturated layer, heat exchange process is constantly going on, in
which the steam is
condensed into water, and heated heavy oil and associated reservoir water flow
to the
production well 2 by gravity.
Tubing strings 6, 7 and 8, 9 are arranged in appropriate wells 1 and 2 so as
to be able
to inject and produce from the opposite ends of the horizontal portions 3 and
4 to enable
controlling mineralization of produced water from both ends of the portion 4;
and to enable
temperature control along the length of sections 3 and 4 by injecting heat-
transfer agent and
extracting products by the downhole pumps 11 and 12 to avoid breakthrough of
the heat-
transfer agent from the injection well I to the production well 2 during
extraction of products,
and increasing the COR of the reservoir 5.
After heating the reservoir and creating the steam chamber, in the process of
extraction
,
from the production well 2, mineralization of produced water from the well 2
is deterinined
not less than once a day directly in the flow of the produced fluids using
measuring devices
(conventionally not shown), for example, sensors disclosed in documents of RU
2231787, RU
2330272 and others. Measuring devices are arranged in the pipe (not shown)
which is
transported produced products or for more precise control at the inlets of the
downhole pumps
11 and 12. The sensors arc placed on the substrate of a hydrophilic material
(for example,
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silicates and the like) having minimum adhesion to hydrocarbon products of the
reservoir 5,
which allows obtaining objective measurements through the long period of
operation. When
installing measuring devices at the inlets of the downhole pumps 11 and 12, or
on the
wellheads, they are operably linked via a control unit (not shown in the
figures) with
corresponding downhole pumps 11 or 12 for controlling production by the said
pumps and
maintaining the lowest possible pressures to eliminate a gas release at an
inlet of the
corresponding pump 11 and 12 taking into account the mineralization.
Increasing water
mineralization raises its boiling temperature since the boiling point of
salted water is higher
than freshwater one. For example, if the solution contains I% NaC1 (at a
pressure of 760 mm
Hg, i.e. 101.325 kPa), water has been boiling at 100.21 C; at 2% - 100.42 C;
at 6% -
10I.34 C; at 15% - 103.83 C; at 18% - 104,79 C; at 21% - 106.16 C; at 24% -
107.27 C; at
27% - 108.43 C; at 29.5% - 109.25 C, etc. For other salts or their
combinations, these data
can vary. Therefore, the dependence of the water boiling point on water
mineralization and
pressure is determined for each field after the analysis of the cores obtained
while drilling of
the reservoir 5. With increasing mineralization, downhole pumps 11 and 12 can
operate in a
wider range and reduce the pressure at the pump inlet of the pump II or 12 to
lower values (to
increase efficiency of the pump 11 or 12 to reduce the mineralization) as
according to
Clausius-Clapeyron equation with increasing pressure, the boiling point
increases, and with
decreasing pressure, the boiling point decreases respectively.
.1n(7 1 ¨4)
= __________________________ - )
cam Mibod. M
wherein Ilia is the boiling point at the inlet of the pump II or 12. K;
P is the pressure at the inlet of the pump 11 or 12, kPa;
. . Pam is the atmospheric pressure (accepted as 101.325 kPa),
kPa;
TbuiLatm. is a boiling point at atmospheric pressure, K;
is the specific heat of evaporation, Pkg:
M is molar mass, kgimol;
R is universal gas constant.
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This relationship is introduced before the operations into the control unit
(controller)
of the pumps 11 and 12 to prevent vaporization at the downhole pump inlets due
to changes in
mineralization of produced water.
After achieving equilibrium, the mineralization of water produced by the pumps
11 and 12 of
the production well 2 is brought by controlling the heat-transfer agent
injection through the
tubing strings 6 and 7 in the injection well 1, and the extraction from the
production well 2 by
pumps 11 and 12 through the tubing strings 8 and 9, with produced water
mineralization most
approximate to the optimal one determined based on the core study.
The reservoir water mineralization decreases when it is mixed with the steam
condensate, and therefore the produced water mineralization has an
intermediate value.
There is an equilibrium relationship between the amount of produced oil and
the
mineralization of the produced water with the subsequent adjustment of the
produced volume
and steam injection taking into account the optimal mineralization obtained by
the core
analysis. This process is resulted by steady injection and production. The
temperature at the
initial stage is controlled in the production well 2 by the temperature
sensors 10 to prevent a
steam breakthrough in the production well 2. Then a stable value of
mineralization is set as
õ close as possible to the optimum value without a steam breakthrough to
the pumps 11 and 12.
This mineralization is called the equilibrium value of mineralization for the
determined fluid
temperature. Violation of this balance is indicated by the change in produced
water
mineralization in samples from the pumps II or 12 while maintaining the fluid
temperature. In
the process of production, the produced water mineralization is determined, at
least once a
day, changes in the samples are analyzed, and dependence of the heavy oil
production on the
produced water mineralization is shown in the figure.
As follows from the graph (Fig. 3), at produced fluid temperature of 100 C
with proper
selection of the produced water mineralization, the displacement efficiency
approaches the
value of 0.7 (70% in a heated zone) taking into account the sweep efficiency
factor (Cõ1,v) for
steam and gravity action on the reservoir 5 (Figures I and 2) is approximately
0.8 (80% of the
reservoir element allocated for a pair of wells 1 and 2) the maximum oil
recovery factor
(CUR) is equal to 56% according to the formula:
COR = Cvyt - Cohv -100% (2)
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Thus, the production at the optimal mineralintion of the produced water can
significantly increase the COR of the productive reservoir 5.
Increasing mineralization of produced water more than by 10% compared to the
equilibrium value of mineralization at predetermined temperature indicates an
increase in the
reservoir water production in the range of temperature 5-15 C. As a result,
the temperature
reduction can take place near the production well 2 and interwell zone, which
leads to uneven
heating of the 'steam -chamber and reducing thermal coverage of the reservoir
clement.
Reducing temperature near the production well and inter-well area leads to the
increased
downhole viscosity of the heavy oil, which in turn reduces oil production and
consequently
reduces the effectiveness of the thermal recovery in general.
For reducing the mineralization of the produced water and raise the
temperature near
the production well 2 and in inter-well area and thereby increase the
uniformity of heating up
of the steam chamber (not shown in figures), it is necessary to increase steam
injection
through the injection well 1 or to reduce production by respective downhole
pumps 11 and/or
12. In this case, the amount of produced water also decreases. With the
increase in steam
injection volume, the stable heating of all the steam chamber volume increases
and stops
further reducing the temperature near the production well 2 and inter-well
area. In this case,
also, the reservoir water is diluted by the discharged condensate, and the
mineralization of the
produced water is reduced. After recovery uniformity of the heating of the
steam chamber,
again an equilibrium between the heavy oil production and the produced water
mineralization
stands taking into account the optimal mineralization at predetermined
temperature, but not
, . . õ
necessarily at the same level, as evidenced by the graph of dependence of the
heavy oil
production on the produced water mineralization.
Reduction of the produced water mineralization by more than 10% compared to
the
equilibrium value also indicates uneven heating of the steam chamber since in
such situation
there is a premature breakthrough of steam to the production well 2. This
leads to
unproductive consumption of steam and, therefore, to increase energy costs.
Breakthrough of
steam to the production well 2 can also lead to the shutdown of technological
equipment due
to exposure to high temperatures. In this regard, when mineralization of
produced water
. . .
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reduces at a predetermined temperature, it is required to reduce the volume of
injected steam
or to increase production. With the increase in product withdrawal, the volume
of produced
cold reservoir water with the increased mineralization also increases, and
therefore the
mineralization of produced water increases. Since the temperature of the
reservoir water, as
said above, is about 5T, increasing in its production will reduce the
temperature near the
production well and in the inter-well area. Increase in production continues
until the
equilibrium between the amount of extracted heavy oil and mineralization of
produced water.
Setup Of equilibrium at a predetermined temperature is judged by the graph of
the heavy oil
production and the mineralization of produced water.
Increasing the measurement frequency up to I measurement per day (as minimum,
the
best is online mode) allows to respond more quickly to changes in
mineralisation (steam
chamber temperature), thus reducing the loss of steam of up to 10% in a
breakthrough,
eliminate supercooling of the steam chamber that, as a consequence, eliminates
the costs up to
15% for an additional heating of the steam chamber caused by these processes
and to increase
the coverage by the heat exposure.
It is found that the oil production rate (Q..ii, in/day) significantly
correlates with the
temperature at the wellhead and the total mineralization of the produced
water, wherein the
flow rate is proportional to the temperature of the produced fluid (T, C),
and inversely
proportional to the mineralization (M, g/1):
= 0.21 T - 1.38 M -4.33 (3)
The correlation coefficient of the model reflects a 79% horizontal well
production rate
variability. The standard error is equal to 2.6, and its value can be used in
setting the
. : ,= , , õ.. õ
boundaries of the predictions for new observations.
By controlling the oil production and steam injection volumes, steam/oil ratio
(SOR)
is evaluated. The said ratio should be maintained at the lowest possible level
to reduce the cost
of steam:
SOR = Qst.m/Qoil (4)
õ . .
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Monitoring uniformity of heating steam chamber using temperature sensors 10 is
disclosed in prior art. However, due to their frequent failures, the
effectiveness of the control
over the process decreases.
It follows from the foregoing that the method of developing heavy oil deposits
allowing carrying out the control of the heat-transfer agent injection and oil
production based
on the analysis of the produced water mineralization is a very simple and
effective way to
control the uniformity of the steam chamber heating and increasing the
efficiency of the heavy
oil recovery.
Examples of specific embodiment
Example I.
The Ashalchinskoye heavy oil pilot is located at a depth of 90 m and
represented by
heterogeneous layers of 20-30 m thick at a temperature of 8 C and pressure of
0.5 MPa. A
pair of horizontal two wellhead wells 1 and 2 (Fig. I) including an injection
well 1 and
production well 2 were drilled. Corresponding horizontal sections 3 and 4 of
the wells were
arranged in parallel one above the other in the vertical plane of the
production reservoir 5 and
equipped with the appropriate tubing strings 6, 7, 8, and 9 configured for
simultaneous
injection of the heat-transfer agent and production from various ends of the
horizontal sections
3 and 4.
The sensors arc installed at the mouth of the outlets of the electrical
submersible
pumps 11 and 12. They were designed to determine the mineralization of the
produced water
and arranged on a hydrophilic substrate. During drilling of wells, cores were
extracted from
õ the productive reservoir 5, said cores showed that the reservoir has
oil saturation of 0.70, a
porosity of 30%, permeability of 2.65 im2. The oil had a density of 960 kg/m3
and a viscosity
of 22000 mPa's, and reservoir water had mineralization of approximately C1õ. =
10 gil.
Mineralization of steam and condensate, respectively, close to zero, i.e., C,
<< I gil. The
mineralization of the produced water may vary in the range from 1 to 10 gil
depending on the
stage of development of heavy oil reservoir 5. Based on the properties of the
reservoir 5, the
volume of stream injected into the well 1, temperature and volume of extracted
products, it
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was determined according to formula 3 (based on the experience of operation of
such wells of
the same deposit) that the greatest amount of extracted oil can be obtained
from the reservoir 5
at a temperature of the produced fluid of about 97 C and the optimum
mineralization of the
produced water of 2A g/l. Before the operation of the horizontal well 2, the
inter-well area
was heated by simultaneous circulation of steam in each of the wells 1 and 2.
In the process of
production of the heavy oil, steam is injected through the injection well I.
Steam extends
upwards and creates increasing in size steam chamber. During production
mineralization of
the produced water is periodically (once a day) determined at the inlets of
the pumps 11 and
12. Determined also the dependence of the oil production on mineralization of
produced
water. At the initial stage of development of the deposit of the heavy oil, an
equilibrium is set
up between the amount of the heavy oil produced and the mineralization of the
produced
water at a temperature of about 100 C, which indicates the uniformity of the
steam chamber
heating. The heavy oil production rate by pumps II and 12 was 12.2 m3/day (SOR
3.7), the
mineralization varied in the range of 2.1-2.4 WI.
Equilibrium (average) value of mineralization was 2.2 gil. Extraction by the
pumps 11 and 12
was increased to a value that excludes gas release from the produced fluid at
the inlet of the
pumps 11 and 12 for approaching to the optimum mineralization. Production rate
increased to
12.8 m3/day (approximately by 5%), and the mineralization 2.3 gil at the
inlets of both pumps
11 and 12 (SOR 3.5). After 34 days of well operation, analysis of
mineralization of the
produced water at the pump II inlet showed that there was increase in
mineralization from 2.3
g/1 to 3.1 g/I, or 34.8%, while the production rate of heavy oil decreased on
this pump from
6.4 m3/day to 3 in3/day (total SOR 5.1). This suggests that the increased
inflow of cold
reservoir water, which helped to reduce the temperature, increasing the
mobility of the heavy
oil, and reducing the uniformity of beating the steam chamber. The amount of
steam injection
at that point was 45 m3/day. Based on the analysis, it was decided to increase
the volume of
steam injection to 55 m3/day for five days. Production by the pump 11 was
reduced by half,
and by the pump 12 was increased by 10% without a gas release from the fluid
at the inlet of
this pump by keeping the pressure at the inlet of this pump not less than 100
kPa. The total oil
production decreased to 9.8 m3/day (SOR 5.6), rather than up to 6 m3/day (as
in similar wells
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operated by the closest analog). After that in 3 days the mineralization of
the produced water
at the pump 11 intake began to decline and reached a value of 2.28 g/I, and
the production of
the heavy oil also increased to 11.3 m3/day (SOR 4.9). The intensity of
extraction by the pump
11 was returned to the initial condition, while for the pump 12 it was lowered
by 10%. Then,
there was stabilization of the heavy oil production at the level of 11.3
m3/day (4% more than
in similar wells of the same deposit), and mineralization changed slightly in
the range of 2.28-
2.4 g/I, which corresponds to the average value of 2.34 g/1 at a temperature
of produced fluid
..õ.. equal to 75 C, which close, to the optimal value, which was maintained
by production
adjustment by the pumps 11 and 12. Later, the temperature increased to 1100 C,
while the total
production was 13 m3/day (SOR 4.2) with water mineralization of 2.7 g/1 (which
is the
optimum value for such flow rate and temperature).
After 32 days, mineralization of the produced water increased from 2.7 g/1 to
3.5 2/1
(an increase of 23% at a fluid temperature of 70 C). Average daily production
of the heavy oil
decreased from 13 m3/day to 10.2 m3/clay (SOR 5.4), which indicated that the
steam chamber
was cooling. The fluid production was reduced from 100 m3/day to 88 m3/day for
aligning the
uniform heating of the steam chamber. After that, within 4 days the
mineralization of the
produced water again began to decline gradually reaching the value of 2.8 g/1,
the extraction
of the heavy oil at the same time began to increase and stabilized at around
12.9 m'lclay (SOR
4.3) at the product temperature of 100 C. COR was 45%, which is 15% more than
that of the
closest analog.
Example 2.
On the experimental plot of the Ashalchinskoye heavy oil deposit located at a
depth of
90m, represented by heterogeneous layers of 20-30 m thick with a temperature
of 8 C. and
pressure of 0.5 MPa a pair of horizontal one-wellhead wells 1 and 2 (Fig. 2)
was drilled. The
said pair consists of an injection well I and a production well 2,
corresponding horizontal
sections 3 and 4 of which are arranged in parallel one above the other in
vertical plane of the
producing reservoir 5 and equipped with the appropriate tubing strings 6, 7,
8, and 9 allowing
simultaneous injection of a heat- transfer agent and product fluids at
different ends of the
corresponding horizontal sections 3 and 4. The sensors are installed at the
mouth of the outlets
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of the electrical submersible pumps 11 and 12. They were designed to determine
the
mineralization of the produced water and arranged on a hydrophilic substrate.
During drilling
of the appraisal well (not shown in Fig. 2), cores were produced from the
reservoir 5, which
showed that the reservoir has oil saturation of 0.70, a porosity of 30%,
permeability of 2.65
urn2. The oil had a density of 960 kg/m3 and a viscosity of 22,000 mPa-s, and
reservoir water
is having a mineralization of approximately Cr, = 10 g/l. Mineralization of
steam and
condensate respectively is close to zero, i.e. C, << 1 g/I. Mineralization of
the produced water
may vary in the range from 1 to 10 g/I depending on the stage of development
of the heavy oil
reservoir 5. Based on the properties of the reservoir 5, the volume of
injected steam into the
.. well 1, the temperature and the volume of extracted fluids (derived from
the operation of such
wells of the same deposit), it was found from the formula (2) that the
greatest amount of the
produced oil from the reservoir 5 would be at the optimum mineralization of
the produced
water of 3.3 gil. During operation, the equilibrium relationship between the
amount of
produced heavy oil (13-13,8 m31day) and the volume of the injected steam of 80
m3/day and
mineralization of produced water (3,58-3,45 WI) at a temperature of extracted
fluids equal to
100 C was achieved. The equilibrium (mean) value of the mineralization was
3.52
However, for such a flow rate, the optimum mineralization was determined based
on core
analyzes as 3.3 g/l. The production rate was increased at the pumps 11 and 12
by 5%. As a
result, the total oil rate was reached 14 m3/day (4% up), and the average
produced water
mineralization was 3.3 g/1 (SOR 5.7). After 32 days of operation, within three
days the
mineralization at the inlet of the pump 12 dropped dramatically and reached a
value of 2.1 g/l.
The change in mineralization amounted to 33% of the equilibrium value, and the
fluid
temperature increased to 120 C. This showed that there was a premature
breakthrough of
steam to the production well 2 resulting in lower exposure of the reservoir,
reduction of the
uniformity of the steam chamber heating and unproductive use of the heat-
transfer agent. For
normalizine the mineralization and consequently the temperature near the
production well, the
production rate by the pump 12 was increased from 43 m3/ day to 49 m3/day. The
produced
water mineralization normalized in 9 days and reached 3.4 g/l. The values of
the fluid
production rate by the pumps 11 and 12 were made equal, and the total amount
established as
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97 m3/day, The heavy oil production decreased initially after the steam
breakthrough and then
stabilized after increasing production rate and remained at 14.2 m3/day (3%
higher than on
similar wells) at the temperature of 110 C (SOR 5.6). After three months of
operation due to
the steam breakthrough, the produced water mineralization at the inlets of
both pumps 11 and
12 decreased to 2.1 g/l, and the flow rate of the heavy oil decreased to 11
m3/day at the
temperature of fluids at 87 C (SOR 7.3). The steam injection rate was
decreased from 80
m3/day to 65 m3/day to restore the balance. The average mineralization at both
pumps 11 and
12 increased to a value of 3.3 WI for four days and subsequently remained at
this level at a
fluid temperature of 90 C. The heavy oil production gradually increased to a
value of 14.1
. 10 m3/day.(SOR 4.6). COR_ was 42%, which is 12% higher than that of the
closest analog.
The described method of high-viscosity oil or bitumen deposits development by
using
a pair of horizontal injection and production wells based on the increasing
number of the
produced water mineralization measurements and approaching of the produced
water
mineralization to the optimal one determined from the core analysis can
increase oil
production by 3-5% and recovery factors by 10-15% at comparable values of
steam/oil ratio.
,
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