Article
Integrated Strategies for Controlling Water Cut in Mature Oil
Fields in Kazakhstan
Zhanat Alisheva 1,† , Kazim Nadirov 2 , Ahmed N. Al-Dujaili 3,† , Gulmira Bimbetova 2 , Zhanna Nadirova 2 ,
Manap Zhantasov 2 , Nurbol Tileuberdi 4, * and Ansagan Dauletuly 5
1
2
3
4
5
*
†
Academic Editor: Maria
Graça Rasteiro
Received: 26 February 2025
Revised: 14 March 2025
Accepted: 17 March 2025
Published: 21 March 2025
Citation: Alisheva, Z.; Nadirov, K.;
Al-Dujaili, A.N.; Bimbetova, G.;
Nadirova, Z.; Zhantasov, M.;
Tileuberdi, N.; Dauletuly, A.
Integrated Strategies for Controlling
Water Cut in Mature Oil Fields in
Kazakhstan. Polymers 2025, 17, 829.
https://doi.org/10.3390/
polym17070829
Copyright: © 2025 by the authors.
Licensee MDPI, Basel, Switzerland.
This article is an open access article
Department of Geography and Environmental Sciences, Al-Farabi Kazakh National University,
Al-Farabi Avenue 71, Almaty 050040, Kazakhstan; alishevazh9@gmail.com
Department of Petroleum Engineering, M. Auezov South Kazakhstan University, Tauke Khan Avenue 5,
Shymkent 160012, Kazakhstan; nadirovkazim@mail.ru (K.N.); gulmnaz@mail.ru (G.B.);
zhanna.nadirova@inbox.ru (Z.N.); manapjan_80@mail.ru (M.Z.)
Petroleum Engineering Department, Amirkabir University of Technology, Tehran 11369, Iran;
ahmed.noori203@aut.ac.ir
Department of Hydrogeology, Engineering and Oil and Gas Geology, Satbayev University, Satbayev St. 22a,
Almaty 050013, Kazakhstan
Institute of Geological Sciences of K.I. Satpayev, Kabanbay Batyr Street 69, Almaty 050013, Kazakhstan;
dauletuly.ansagan@mail.ru
Correspondence: 1983nureke@gmail.com
These authors contributed equally to this work.
Abstract: This study analyzed the physical and hydrodynamic characteristics of various
horizons in the Kumkol and East Kumkol oil fields by special core analysis to integrate
strategies for controlling water cuts and well-intervention procedures for a more effective
oil flow rate in mature oil fields in Kazakhstan. The results indicated that the recovery
factor (RF) for Horizon I is 48.3% (98.7% water cut), while Horizon II has an RF of 45.5%
(97.9% water cut). Horizon III has an RF of 52.7% (98.8% water cut), and Horizon IV has
an RF of 32.6% (98.6% water cut) in the Kumkol Field. In the East Kumkol Field, Horizon
I has an RF of 49.5% (96.7% of water cut), and Horizon II has an RF of 31% (94.9% of
water cut). The average increase in oil flow rate from well optimization ranges from 5.3 to
6.4 tons per day in the Kumkol Field and 5.22 tons per day in the East Kumkol Field. The
maximum increase in oil flow rate is 10.8 tons/day for Horizon I in the Kumkol Field and
6.9 tons/day for Horizon II in the East Kumkol Field. The well-intervention procedures are
more effective in the Kumkol Field than in the East Kumkol Field. Given the high water
cut observed in these mature reservoirs, this study also examines polymer flooding as an
enhanced oil recovery (EOR) technique to improve oil displacement efficiency and reduce
water production. Polymer flooding has been successfully implemented in high water-cut
reservoirs, including the Uzen field in Kazakhstan, demonstrating its ability to modify fluid
filtration profiles and enhance oil recovery. The feasibility of applying polymer flooding in
the Kumkol and East Kumkol fields is analyzed, along with a comparison of its effectiveness
against conventional water shut-off and well-intervention methods. Additional research is
needed to assess polymer retention, reservoir compatibility, and the economic feasibility of
large-scale implementation.
Keywords: Kumkol and East Kumkol fields; polymer flooding; water cut; recovery factor;
well-intervention; polymer retention; optimization
distributed under the terms and
conditions of the Creative Commons
Attribution (CC BY) license
(https://creativecommons.org/
licenses/by/4.0/).
Polymers 2025, 17, 829
https://doi.org/10.3390/polym17070829
Polymers 2025, 17, 829
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1. Introduction
In the oil and gas extraction process, the production of unwanted water, known as
water cut or water shut-off, remains one of the most difficult situations to manage and
overcome [1]. In fact, effective control of water cut is of utmost importance since oil and gas
are characterized by their non-renewable character, and the demand for energy is more and
more considerable all over the world [2]. Furthermore, reducing environmental deterioration and enhancing hydrocarbon recovery rely on the efficiency of water management in oil
fields [3–5]. Moreover, dealing efficiently with water cut is economical. Precisely, this can
prevent huge unwanted expenses provoked by enormous unwanted water production in
the oil industry [6]. In general, as noted in [7], oil wells must be abandoned unexpectedly,
leading to a loss of productivity when undesirable water production is excessive. It is more
than necessary to strengthen strategies that gradually lead to fairer control of water cut
in mature oil fields. Typically, undesirable water is mainly caused by leaking tubing or
casings from aging oil fields [8]. It is worth mentioning that large water cuts usually come
from mature oil fields [9,10]. Since mature oil fields contribute significantly to global oil
production [11], there is great interest in exploring and developing them.
A relevant literature review reveals that many strategies are usually developed or
employed to manage water cut in aging oil fields. They are mostly mechanical and chemical
and aim to gradually improve the efficiency of water evacuation. However, each of these
strategies has its peculiarities and limitations. For instance, Ref. [9] utilized diversion wells
as a technology to boost oil recovery in reservoirs facing enormous water shut-off [12].
However, this strategy is best suited for oil reservoirs located in fault blocks [13,14]. To
diminish water intrusion into oil reserves and thus enhance recovery up to 5%, Ref. [15]
believed that a low permeable barrier can be implemented by low salinity water in the short
term. However, the applicability of such a method requires the existence of in situ movable
fines, which are contained within the reservoir of interest. In order to better control the
Chinese Changqing oil field, an interesting method consisting of characterizing waterflood
direction and front has been proposed by [16]. According to them, such a method can
increase the oil productivity of a given reservoir by 40% because it considerably reduces
water cuts for producers. Nonetheless, such a method requires strong mobilization since
the waterflood direction and front direction must be characterized using numerical and
statistical techniques. As part of deep learning techniques, Long Short-Term Memory
(LSTM) is proposed by [17] to forecast the productivity of oil fields at the stage of ultra-high
water shut-off. Such a procedure relies on a huge amount of relevant data to provide good
accuracy. In their aim to mitigate the exaggerated water content reduction in aging oil
fields, Ref. [18] address reservoir heterogeneity by adequately applying bulk polymer gels.
Although gel treatments are generally economical, they are most effective in fractured
reservoirs where carbonate rocks are predominantly common. Flow control valves can
be used as a strategy to control high water content in aging oilfields, as pointed out
in [19]. However, this strategy does not provide optimized results since it leads to reduced
oilfield production. Recently, to mitigate excessive water cut in mature oil fields, a novel
nanomaterial reinforced particle gel (NRPG) has been developed by [20]. However, this
strategy needs a special mechanism of polymerization with strong adaptability.
In addition to mechanical and hydrodynamic methods for managing water cut, there
has been a growing interest in chemical methods for enhancing oil recovery in recent
years, particularly polymer flooding. In Kazakhstan, previous attempts have been made
to apply polymers in the Uzen field, and studies have been conducted to evaluate the
effectiveness of polymer flooding in high water-cut reservoirs. The use of polymers allows
for the modification of fluid filtration profiles in the reservoir, reducing water mobility and
improving oil displacement efficiency. Given the high water cut observed in mature fields
Polymers 2025, 17, 829
3 of 26
like Kumkol, further research is warranted to assess the feasibility and potential efficiency
of polymer flooding as an advanced enhanced oil recovery (EOR) technique for optimizing
reservoir performance and mitigating excessive water production.
In Kazakhstan, managing water cut is challenging, especially in mature fields like
Tengiz Karachaganak [21], Uzen [7], and Akhmetzhan [22]. For example, the North Buzachi
field has seen a drop in heavy oil production due to high viscosity and inefficiencies after
20 years of cold-water flooding [23]. Attempts with water shut-off, polymer flooding, and
perforation adjustments have shown limited success. Gas-Steam Composite Stimulation
(GSCS), successfully tested in Mortuk, increases sweep efficiency to 40% and oil recovery
to 33.4%, compared to 12% with water flooding, and reduces water cut from 97% to 50%,
making it a promising cost-effective solution [24,25].
This article outlines a comprehensive strategy to significantly reduce the high water
cut observed in aging oil fields within the Kumkol oilfield in Kazakhstan. The proposed
approach addresses the challenges of mature reservoirs by incorporating advanced technologies, optimized water management practices, and customized solutions to enhance oil
recovery while minimizing water production issues.
Theoretical Justification of Polymer Flooding
Polymer flooding is a widely recognized enhanced oil recovery (EOR) technique that
involves injecting a polymer solution, such as polyacrylamide, into the reservoir to increase
the viscosity of the displacing fluid and reduce its mobility ratio. This process effectively
improves the sweep efficiency by mitigating water channeling through high-permeability
zones and ensuring a more uniform displacement front [26].
One of the critical factors determining the success of polymer flooding is the ability
of the injected polymer to maintain its viscosity under varying reservoir conditions, particularly temperature fluctuations. At elevated temperatures, polymer degradation and
viscosity loss can significantly impact displacement efficiency, necessitating the selection of
thermally stable polymers. The following table presents experimental data on the viscosity
behavior of polymer solutions across different temperature ranges, providing insights into
the thermal stability of potential polymer candidates for the Kumkol reservoir.
The viscosity of polymer solutions is highly dependent on temperature, as higher
temperatures can lead to polymer degradation and reduced efficiency in improving the
mobility ratio. To assess the thermal stability of the selected polymer system, viscosity
measurements were conducted at different temperatures. The results, summarized in
Table 1, illustrate the decline in polymer viscosity as the temperature increases, highlighting
the need for thermally stable polymers in high-temperature reservoirs such as Kumkol.
Table 1. Viscosity reduction of polymer solution at different temperatures.
Temperature
(◦ C)
Polymer Solution Viscosity
(cP)
Polymer Solution Viscosity
(Pa·s)
30
40
50
60
70
80
25
20
15
12
10
8
0.025
0.020
0.015
0.012
0.010
0.008
As shown in Table 1, polymer viscosity decreases significantly with rising temperature,
with a nearly 70% reduction observed between 30 ◦ C and 80 ◦ C. This trend underscores the
necessity of selecting temperature-resistant polymer formulations to ensure the efficiency
of polymer flooding under the reservoir conditions of the Kumkol Field.
Polymers 2025, 17, 829
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It is important to note that the viscosity values presented in Table 1 were measured
using a rotational rheometer (Anton Paar MCR series) at a constant shear rate of 10 s−1 .
This controlled shear rate ensures that the recorded viscosity reflects only the temperaturedependent behavior of the polymer solution, minimizing the influence of shear-thinning
effects. At low polymer concentrations (≤1000 ppm), the solutions exhibit near-Newtonian
behavior, making the viscosity-temperature relationship valid under these conditions. However, at higher concentrations, shear-thinning effects become more pronounced, requiring a
more detailed rheological characterization for practical field applications.
For industry-standard applications, viscosity values are reported in centipoise (cP),
with corresponding SI unit equivalents (Pa·s) provided in parentheses for reference. The
conversion factor used is 1 cP = 0.001 Pa·s.
To optimize the polymer flooding process, laboratory experiments were conducted
to determine the optimal polymer concentration for maximizing the oil displacement
factor. The experimental results, summarized in Table 2, indicate that the highest oil
recovery factor is achieved at a polymer concentration of 0.15–0.20% (previously expressed
as 1500–2000 ppm), beyond which additional increases provide negligible economic or
technical benefits.
Table 2. Determination of the optimal polymer concentration for Kumkol Field.
Polymer Concentration (ppm/%)
Oil Recovery Factor (%)
500
40
1000 (0.10%)
50
1500 (0.15%)
55
2000 (0.20%)
57
2500 (0.25%)
58
Given the temperature sensitivity of polymer solutions (Table 1) and the observed
recovery efficiency at different concentrations (Table 2), selecting a polymer formulation
that balances viscosity retention at high temperatures and optimal concentration levels is
crucial for effective polymer flooding.
To further refine polymer selection, additional laboratory tests were conducted to
assess the performance of different polymer types under reservoir conditions. The key
characteristics of the tested polymers are summarized below (Table 3):
Optimal polymer concentration: 0.10–0.15%
Reduction in water mobility under reservoir conditions: 35–50%
Increase in oil displacement efficiency: 15–20%
Optimal polymer solution viscosity for Kumkol conditions: 10–15 cP.
Table 3. Laboratory analysis of polymer characteristics and their effect on oil recovery.
Polymer Type
Solution Viscosity (cP)
Increase in Oil Recovery
Factor (%)
Polyacrylamide
10–15
15–20
Crosslinked Polyacrylamide
20–30
20–25
Polymer with Nanoparticles
30–40
25–30
Among the tested polymers, nanoparticle-enhanced polymers exhibited the highest
improvement in oil displacement efficiency, increasing the recovery factor by 25–30%. This
suggests that nanoparticle-based polymers are a promising choice for the Kumkol reservoir,
Polymers 2025, 17, 829
This suggests that nanoparticle-based polymers are a promising choice for the Kumkol
5 of 26
reservoir, particularly given their enhanced stability and superior water mobility
reduction properties. These findings highlight the potential of advanced polymer
particularly given
their enhanced
stability
andstrategies
superior water
mobility reduction
properties.
formulations
to optimize
polymer
flooding
and maximize
oil recovery
under
These
findings
highlight
the
potential
of
advanced
polymer
formulations
to
optimize
the given reservoir conditions.
polymer flooding strategies and maximize oil recovery under the given reservoir conditions.
2. Geological and Hydrocarbon Potential of the Kumkol and East
2. Geological and Hydrocarbon Potential of the Kumkol and East
Kumkol Deposits
Kumkol Deposits
2.1. Geological Setting
2.1. Geological Setting
The Kumkol and East Kumkol oil fields are located within the Ashisay structural
The Kumkol and East Kumkol oil fields are located within the Ashisay structural
system of Paleozoic horst-anticlines, positioned in the Aryskum trough of the South
system of Paleozoic horst-anticlines, positioned in the Aryskum trough of the South TurTurgay depression [27] (Figure 1). This region forms a part of the Turan tectonic plate and
gay depression [27] (Figure 1). This region forms a part of the Turan tectonic plate and
is characterized by its complex geological formations, which include a series of uplifted
is characterized by its complex geological formations, which include a series of uplifted
blocks and folded anticlines [28]. These structural features play a critical role in
blocks and folded anticlines [28]. These structural features play a critical role in hydrohydrocarbon accumulation and have made the area a significant contributor to regional
carbon accumulation and have made the area a significant contributor to regional oil
oil production [29].
production [29].
Figure1.1.Structural
Structurallocation
locationof
ofKumkol
Kumkoloilfield
oilfield[30].
[30].
Figure
Toassess
assessthe
thefeasibility
feasibility
polymer
flooding,
Table
4 presents
the geological
key geological
To
ofof
polymer
flooding,
Table
4 presents
the key
and
and
physical
parameters
of
the
Kumkol
reservoir,
including
formation
water
salinity,oil
oil
physical parameters of the Kumkol reservoir, including formation water salinity,
viscosity, and
and other
other critical
critical reservoir
reservoir characteristics.
characteristics.
viscosity,
These
reservoir
conditions
are
highly
for polymerfor
flooding
implementation,
These reservoir conditions are favorable
highly favorable
polymer
flooding
as
the
process
can
significantly
reduce
water
saturation
in
productive
zones
and
enhance
implementation, as the process can significantly reduce water saturation in productive
the
oil
displacement
efficiency.
zones and enhance the oil displacement efficiency.
The South Turgay Basin features an Early Mesozoic basement and upper unconformity
sedimentary layers. These comprise a Jurassic rift system and a Cretaceous quaternary
post-rift depression sedimentary system [31] (Figure 2). During the Early–Middle Jurassic,
lacustrine mudstone dominated the sedimentary layers, while the lateral margins of the
Polymers 2025, 17, 829
6 of 26
graben often transitioned into coarse-grained gravel and estuarine clastic rocks [32–34]. The
estuarine deposits, which are widely distributed, originated from the uplifted basement
along the lateral margins of the graben [35]. At the Jurassic–Cretaceous boundary, riftrelated sedimentation occurred as tectonic activity in the grabens subsided [36]. The
basin shifted into a phase of slow subsidence, with localized denudation in some areas.
This process gave rise to the basal sandstone of the Cretaceous, known as the Aryskum
Formation [37]. Deltaic sediments were extensively deposited during the basin’s filling
phase, while fluvial systems were more prominent in the northern parts of the South Turgay
Basin [38]. During this time, river systems expanded, lake levels declined, and the water
bodies gradually migrated southward. Semi-deep lake deposits are also evident in the
Bozingen Graben [39].
Table 4. Reservoir characteristics.
Parameter
Value
Average Reservoir Temperature
52–60 ◦ C
Formation Water Salinity
49.784 mg/L
Oil Viscosity
1–10 cP
Reservoir Permeability
100–500 mD
Porosity
18–22%
Water Cut
98.4%
Oil Recovery Factor (ORF)
35–50%
The geological framework comprises metamorphosed Paleozoic-Proterozoic basement
rocks overlain by Mesozoic and Cenozoic sedimentary layers [40]. The basement features
sericite-quartzite schists, quartzite, and hydromica-kaolinite clays, with thicknesses ranging from 16 to 267 m. Overlying Mesozoic formations include Jurassic and Cretaceous
terrigenous deposits. The Jurassic system features productive horizons J-I through J-IV
within the Doschanskaya and Kumkol suites [41], while the Cretaceous system includes
the Aryskum horizon in the Daul formation, which contains two main oil-bearing zones
(M-I and M-II) [42] (Figure 2).
The Kumkol deposit exhibits commercial hydrocarbon potential across
multiple horizons:
1.
2.
3.
4.
5.
6.
7.
Horizon M-I: A layered, arched oil deposit with dimensions of 14.2 × 4.6 km and a
height of 48.7 m.
Horizon M-II: A massive oil deposit, 5.2 × 2.7 km in size and 25 m high.
Horizon J-I: Contains the largest oil-bearing area with a layered, arched deposit
measuring 19.7 × 8.8 km and 133.3 m in height (gas cap: 43.8 m; oil zone: 89.5 m).
Horizon J-II: Features a layered, arched deposit with dimensions of 18 × 7.8 km and
oil-bearing and gas-bearing areas of 61,249 and 2728 thousand m2 , respectively.
Horizon J-III: Comprises three deposits, including a gas-capped oil deposit and two
smaller accumulations, with oil-bearing areas up to 38,083 thousand m2 .
Horizon J-IV: A lithologically limited gas and oil deposit, 4.0 × 5.8 km in size and
37.3 m in oil thickness.
Horizon PZ1 -PR: Includes four deposits, with oil and gas caps, hosted in quartzsericite schists and quartzites, exhibiting oil-saturated thicknesses of 0.8 to 12.5 m
(Figure 3 and Table 5).
The heterogeneity of horizons and reservoir beds is characterized by sandiness and
dissection coefficients [43]. Table 5 provides data on reservoir bed thickness, average values,
Polymers 2025, 17, x FOR PEER REVIEW
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and variations, along with reservoir properties and oil saturation. These metrics are
Polymers 2025, 17, x FOR PEER REVIEW
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28
from GIS and core analysis.
Figure
2. Stratigraphiccolumn
columnmap
map of the
[35].
Figure
2. Stratigraphic
the South
SouthTurgay
TurgayBasin
Basin
[35].
Figure 2. Stratigraphic column map of the South Turgay Basin [35].
Figure 3. Hydrocarbon potential units of the Kumkol basin [13].
Figure
basin [13].
[13].
Figure 3.
3. Hydrocarbon
Hydrocarbon potential
potential units
units of
of the
the Kumkol
Kumkol basin
Polymers 2025, 17, 829
8 of 26
Table 5. Statistical indicators of heterogeneity of productive horizons of the Kumkol deposit.
Horizon, Object
Number of Wells Used
for Determination
Sandiness Coefficient, Units
Coefficient of Dismemberment,
Fractions of Units
Average
Variations
Average
Variations
Distribution Coefficient,
Fractions of Units
M-I
628
0.621
0.048
2.70
0.123
1
M-II
440
0.756
0.022
7.70
0.213
1
J-I
931
0.540
0.175
4.07
0.214
0.997
J-II
765
0.712
0.086
2.11
0.216
0.976
J-III
610
0.777
0.032
2.24
0.229
0.954
J-IV
188
0.465
0.316
2.55
0.380
0.977
PZ-PR
100
0.491
0.365
3.14
0.235
0.929
2.2. Hydrocarbon Potential
The field’s recoverable reserves are estimated at 54,278 thousand tons, classified
under categories A, B, and C1. These classifications are based on rigorous geological and
geophysical analysis, with category A representing the highest degree of certainty [44]. This
substantial reserve base underscores the Kumkol Field’s importance in meeting regional
energy demands and sustaining long-term production targets.
As of recent evaluations, the cumulative production from the Kumkol Field has
reached approximately 43,200 thousand tons, which equates to 79.6% of the initial recoverable reserves [45]. This impressive recovery rate reflects the implementation of advanced
extraction technologies and efficient reservoir management practices [46]. However, as
production nears the economic limit of recoverability, challenges arise in accessing the
remaining reserves. Strategies such as enhanced oil recovery (EOR) techniques are being
considered to optimize extraction [47].
This study was achieved due to a late stage of development for the field, which has
declining oil production. The main reasons are a significant reserve depletion degree, a
high water cut of the extracted products, and complete field drilling. Since the beginning
of development in 2017, oil production at the asset has amounted to 552.2 thousand tons.
Cumulative oil production at both fields was 43,200 thousand tons, or 79.6% of the initial
recoverable reserves, with a water cut of 98.4%.
3. Data and Methods
The physical and hydrodynamic characteristics were determined based on the results
of special core analysis for 1173 samples from different horizons of Kumkol and East
Kumkol oil fields (Tables 6 and 7). The average petrophysical properties (permeability,
porosity, and initial oil saturation) were determined [48,49] based on the results of core
analysis from different horizons of the Kumkol Field (Table 7) and the East Kumkol oil field
(Table 8).
Table 6. Number of core sampling for each horizon in the East Kumkol oil field.
Parameter/Horizon
M-I
M-II
J-I
J-II
J-III
J-IV
Total
P.Z.
Number of samples
95
132
378
257
241
52
1155
95
The characteristics of surface tension, wetting angle, and fluid densities identified
using core analysis are listed in Table 9.
The hydrocarbon reserves of the Kumkol Field were first calculated in 1987. The last
calculation of oil reserves was performed in 2012, and gas and condensate reserves in 2008.
In the same year, the reserves of the PZ1-PR formation were promptly reviewed (within
the territory of activity of Turgai). Almost all of the oil reserves at the Kumkol Field are
Polymers 2025, 17, 829
9 of 26
classified as industrial, with less than 1% of the total reserves classified as non-industrial.
Most oil reserves are concentrated in the M-I and J-I formations (28–29% each) (Figure 4).
Table 7. Characteristics of reservoir properties and oil saturation of Kumkol Field.
Horizon
Method
Name
K, 10−3 µm2
φ, Fraction
Laboratory
Research cores
Average value
2584
0.293
Coefficient of variation
0.82263
0.00026
M-I
Geophysical
Research wells
Laboratory
Research cores
M-II
Geophysical
Research wells
Laboratory
Research cores
J-I
Geophysical
Research wells
Laboratory
Research cores
J-II
Geophysical
Research wells
Laboratory
Research cores
J-III
J-IV
PZ +
PR
Average value
Coefficient of variation
0.26
0.56
0.006
0.041
Average value
1337
0.266
Coefficient of variation
1.3043
0.0158
Average value
Coefficient of variation
0.27
0.57
0.001
0.034
Average value
313
0.242
Coefficient of variation
3.9669
0.0338
Average value
Coefficient of variation
0.23
0.61
0.077
0.048
Average value
1891
0.264
Coefficient of variation
7.9627
0.03141
Average value
Coefficient of variation
Soi, Units
0.25
0.64
0.008
0.05
Average value
634
0.234
Coefficient of variation
2.5279
0.0216
Geophysical
research wells
Average value
0.25
0.64
Coefficient of variation
0.016
0.05
Laboratory
Research cores
Average value
145.9
0.215
Coefficient of variation
5.5997
0.0323
Geophysical
Research wells
Average value
0.21
0.54
Coefficient of variation
0.134
0.029
Laboratory
Research cores
Coefficient of variation
Geophysical
Research wells
Average value
0.14
0.54
Coefficient of variation
0.02
0.029
Average value
0.2
0.077
Table 8. Characteristics of reservoir properties and oil saturation of East Kumkol Field.
Horizon
J-II
Porosity, Fractions
of Units
Initial Oil
Saturation, Units
Name
Laboratory
Research cores
Average value
1.8
0.289
Coefficient of variation
0.039–6.323
0.204–0.336
Geophysical
Research wells
Average value
0.26
0.51
Coefficient of variation
0.013
0.015
Laboratory
Research cores
Average value
0.23
0.239
Coefficient of variation
0.024–1.082
0.192–0.281
Geophysical
Research wells
Average value
0.21
0.58
Coefficient of variation
0.035
0.034
Laboratory
Research cores
Average value
3.952
0.277
Coefficient of variation
0.015–12.041
0.179–0.327
Geophysical
Research wells
Average value
0.24
0.59
Coefficient of variation
0.022
0.031
M-I
J-I
Permeability, 10−3 µm2
Determination Method
The II development object is the main one regarding the volume of recoverable oil
reserves (48%) (Figure 5).
Oil–water
Water–gas
Oil–water
Oil–water
Polymers
2025, 17, 829
Parameter
Water–gas
Oil–water
Oil–water
Layer
30
30
660
1051
Laboratory
72
0
Laboratory The hydrocarbon30
660
reserves of the Kumkol 30
Field were first calculated
in 1987.1051
The last
Layer calculation of oil reserves
30 was performed in 30
660
1051
2012, and gas and condensate reserves
10 ofin
26
2008. In the same year, the reserves of the PZ1-PR formation were promptly reviewed
Thethe
hydrocarbon
Kumkol
Fieldall
were
firstoil
calculated
The last
(within
territory ofreserves
activity of
of the
Turgai).
Almost
of the
reservesin
at1987.
the Kumkol
Table
9. Characteristics
surface
wetting
and
fluid
densities.
calculation
of oil reserves
wastension,
performed
inangle,
2012,
and
gas
and
condensate
reserves
in
Field
are
classified
as of
industrial,
with less
than
1% of
the
total
reserves
classified
as non2008.
In
the
same
year,
the
reserves
of
the
PZ1-PR
formation
were
promptly
reviewed
industrial.Surface
Most Tension
oil reserves are concentrated in the M-I and J-I formations (28–29% each)
3
Terms and Conditions
Wettingof
Angle
(θ), ◦ Almost
Densityall
of Oil,
kg/m
Density of
kg/m3
(within4).
the(a),territory
Turgai).
of the
oil reserves
at Water,
the Kumkol
Dyne/cm of activity
(Figure
72
0
LaboratoryField are classified
as industrial, with
less than 1% of the total reserves classified as non30 oil reserves are concentrated
30
660and J-I formations (28–29%
1051
Laboratoryindustrial. Most
in the M-I
each)
Layer (Figure 4).
30
30
660
1051
Figure 4. Distribution of initial geological oil reserves by layers of the Kumkol Field.
The II development object is the main one regarding the volume of recoverable oil
Figure 4.
4. (48%)
Distribution
of initial
initial geological
geological oil
oil reserves
reserves by
bylayers
layersof
ofthe
theKumkol
KumkolField.
Field.
reserves
(Figure
5).
Figure
Distribution
of
The II development object is the main one regarding the volume of recoverable oil
reserves (48%) (Figure 5).
Figure 5.
5. Distribution
Distribution of
of initial
initial recoverable
recoverable oil
oil reserves
reserves by
by development
development sites
sites of
of the
the Kumkol
Figure
Kumkol Field.
Field.
The hydrocarbon reserves of the Vostochny Kumkol deposit were last approved
in 2013. The initial geological/recoverable oil reserves of the East Kumkol Field in the
Figure 5. Distribution of initial recoverable oil reserves by development sites of the Kumkol Field.
contract territory of JSC Turgai-Petroleum amount to 4786/2022 thousand tons, and the
initial geological/recoverable reserves of dissolved gas amount to 80/32 million m3 , and
the presence of gas caps has not been established. The main one regarding the volume of
recoverable oil reserves (85%) is the II development object (Figure 6), which includes the J-I
and J-II layers. Thus, most of the reserves are concentrated in the Jurassic deposits.
Production and injection data of the Kumkol deposit and East Kumkol deposit for the
period under study between 2013 to 2017 are illustrated in Figures 7 and 8, respectively.
The residual recoverable hydrocarbon reserves of the field as of 01.01.2018 are (geological/recoverable): oil—45.550/10.653 thousand tons in category A + B + C1, 58/35 thousand
Polymers 2025, 17, 829
2013. The initial geological/recoverable oil reserves of the East Kumkol Field in the
initial geological/recoverable reserves of dissolved gas am
contract territory of JSC Turgai-Petroleum amount to 4786/2022 thousand tons, and the
thegeological/recoverable
presence of gas
capsofhas
notgas
been
established.
The
ma
initial
reserves
dissolved
amount
to 80/32 million
m
11 of
263, and
the presence of gas caps has not been established. The main one regarding the volume of
recoverable oil reserves (85%) is the II development objec
recoverable oil reserves (85%) is the II development object3(Figure 6), which includes the
tons in category C2 gas dissolved in oil—4428/1 170 million m in category A + B + C1 and
J-I J-I
and and
J-II layers.
most of
the reserves
are of
concentrated
in the Jurassic
J-IIThus,
Thus,
most
the reserves
aredeposits.
concentra
3 layers.
0.4/0.2 million m in the category (Tables 10 and 11).
Figure 6. Distribution of initial recoverable oil reserves by development sites of the East Kumkol
Field.
Production and injection data of the Kumkol deposit and East Kumkol deposit for
the period under study between 2013 to 2017 are illustrated in Figures 7 and 8,
Figure 6. Distribution of initial recoverable oil reserves by development sites of the East Kumkol Field.
respectively.
Figure 6. Distribution of initial recoverable oil reserves by dev
Field.
Production and injection data of the Kumkol depos
the period under study between 2013 to 2017 are il
respectively.
Figure
7. Production
dataofofthe
theKumkol
Kumkol
deposit
the period
between
2013
and
Figure
7. Productionand
andinjction
injction data
deposit
for for
the period
between
2013 and
2017.
2017.
The residual oil reserves (geological/recoverable) at the field amount to
3189/425
thousand
tons, and dissolved
gas inreserves
oil amounts
to 58.1/10
million
m3 . All are
The residual
recoverable
hydrocarbon
of the
field as
of 01.01.2018
reserves are classified as ABC1 (Tables 12 and 13).
(geological/recoverable): oil—45.550/10.653 thousand tons in category A + B + C1, 58/35
Polymers 2025, 17, 829
12 of 26 A +
thousand tons in category C2 gas dissolved in oil—4428/1 170 million m3 in category
B + C1 and 0.4/0.2 million m3 in the category (Tables 10 and 11).
Figure
Productionand
andinjection
injection data
data of the
forfor
thethe
period
between
20132013 to
Figure
8. 8.
Production
the East
EastKumkol
Kumkoldeposit
deposit
period
between
to 2017.
2017.
Table 10. Status of oil reserves at the Kumkol Field as of 1 January 2018.
Table 10. Status of oil reserves at the Kumkol Field as of 01.01.2018.
Initial Oil Reserves, Thousand Tons
Objects
Objects
I/MI
+ II+ II
I/MI
II/J-T
+ J-II
II/J-T
+ J-II
III/J-III
III/J-III
IV/J-IV+
(PZ(PZ
1- PR)
IV/J-IV+
1 - PR)
Total
Total
Initial Oil Reserves, Thousand Tons Current Reserves, Thousand Tons
Current Reserves, Thousand Tons
On the
Balance
Sheet Sheet
OnState
the State
Balance
Geological
Extractable
Geological
Extractable GeologicalGeological Extractable
Extractable
ABC1
C2
ABC1
C2
ABC1
C2
ABC1 C2
C2ABC1 ABC1
C2
ABC1
C2
ABC1
C2
27.685
- 16.302 16.30214.316
2933
27.685
14.316
2933
41.300 58
58 25.308 25.308
35
22.497
58
6506
35
41.300
35
22.497
58
6506
35
17.484
- 10.358 10.3588275
1149
17.484
8275
1149
684
288
461
65
684
288
461
65
87.153
58
52.256
35
45.550
58
10.653
35
87.153
58
52.256
35
45.550
58
10.653
35
Polymers 2025, 17, 829
13 of 26
Table 11. Status of dissolved gas reserves of the Kumkol Field as of 1 January 2018.
Initial Reserves of Dissolved Gas, Million m3
Current Reserves, Million m3
On the State Balance Sheet
Objects
Geological
Extractable
Geological
Extractable
ABC1
C2
ABC1
C2
ABC1
C2
ABC1
C2
I/MI + II
340
-
200
-
184
-
44
-
II/J-T + J-II
5454
0.4
3341
0.2
3048
0.4
935
0.2
III/J-III
2290
-
1357
-
1100
-
167
-
IV/J-IV+ (PZ1 - PR)
126
-
54
-
96
-
24
-
Total
8210
0.4
4953
0.2
4428
0.4
1170
0.2
Table 12. Status of oil reserves at the East Kumkol Field as of 1 January 2018.
Initial Oil Reserves, Thousand Tons
Current Reserves, Thousand Tons
On the State Balance Sheet
Objects
Geological
Extractable
Geological
Extractable
ABC1
C2
ABC1
C2
ABC1
C2
ABC1
C2
I/MI
622
-
305
-
314
-
−2
-
II/J-T + J-II
4164
-
1717
-
2875
-
427
-
Total
4786
-
2022
-
3189
-
425
-
Table 13. Status of dissolved gas reserves of the East Kumkol Field as of 1 January 2018.
Initial Reserves of Dissolved Gas, Million m3
Objects
Current Reserves, Million m3
On the State Balance Sheet
Geological
Extractable
Geological
Extractable
ABC1
C2
ABC1
C2
ABC1
C2
ABC1
C2
I/MI
0.5
-
0.2
-
0.2
-
−0.1
-
P/UT + P
79.8
-
32
-
58
-
10
-
Total
80
-
32
-
58
-
10
-
4. Results and Discussion
According to the core data description, the reservoirs at the field are represented by
sandstones, sandy rocks with insignificant layers of clay rocks and clays, and less often
siltstones, with a low content of carbonate cement. Sandstones of Neocomian deposits
are usually fine-grained and often very poorly cemented. In the deposits of the Kumkol
suite, the sandstones are also fine-grained and poorly cemented, especially in the Yu-I
and Yu-II horizons. There are fine-medium-grained, in thin interlayers—coarse-mediumgrained sand varieties. In the deposits of the Doshchanskaya suite, the amount of mediumgrained and coarse-medium-grained varieties increases. The lithological and petrophysical
characteristics of the Pz + PR deposits with the addition of core sampling from well
5014 have not changed. The rocks are represented by pyroxene andesite porphyrites, with
significant secondary changes of the greenstone metamorphism type, quartzite, weathered
to varying degrees, and schists. The field is at a late stage of development with declining oil
production. The main reasons are a significant degree of reserves depletion, characterized
Polymers 2025, 17, 829
14 of 26
Polymers 2025, 17, x FOR PEER REVIEW
15 of 28
by high water cut of the extracted products, and complete field drilling. Since the beginning
of development, 41,603 thousand tons of oil have been produced at the field, or 79.6% of
the
object IV, units,
are developed
with IV,
theare
reservoir
pressure
theNIR.
field,All
or production
79.6% of theunits,
NIR.except
All production
except object
developed
with
maintenance
by
reinjecting
the
produced
water
into
the
reservoir.
Since
the
beginning
of
the reservoir pressure maintenance by reinjecting the produced water into the reservoir.
3
development,
327,970ofthousand
m of water
have
been injected
into the
reservoirs.
Current
Since the beginning
development,
327,970
thousand
m3 of water
have
been injected
into
compensation
is
101%,
accumulated—91.7%.
the reservoirs. Current compensation is 101%, accumulated—91.7%.
4.1.
4.1.Horizon
HorizonObject
ObjectI—Kumkol
I—KumkolField
Field
The
development
system
The development systemisismarginal
marginalflooding.
flooding.The
Thedistance
distancebetween
betweenwells
wellsisis250
250m.
m.
The
Thedynamics
dynamicsofofthe
themain
maindevelopment
developmentindicators
indicatorsare
arepresented
presentedininFigure
Figure9A,B.
9A,B.
Figure
Figure9.9.(A,B)
(A,B)Dynamics
Dynamicsofofthe
themain
maindevelopment
developmentindicators.
indicators.(C)
(C)Map
Mapof
ofaccumulated
accumulatedselections.
selections.
(D) Map of current selections for Object I in the Kumkol Field.
(D) Map of current selections for Object I in the Kumkol Field.
Since the beginning of development, 13,369 thousand tons of oil, or 82.0% of the
Since the beginning of development, 13,369 thousand tons of oil, or 82.0% of the
reserve, have been produced. A total of 145,648 thousand m3 3of water has been pumped
reserve, have been produced. A total of 145,648 thousand m of water has been pumped
into the formations. The current oil flow rate is 4.9 tons/day, and the liquid flow
into the formations. The current oil flow rate is 4.9
tons/day, and the liquid flow rate is
3 /day.
rate is 397.3 tons/day. Well injectivity is 560.9 m
Current compensation is 96%,
3
397.3 tons/day. Well injectivity is 560.9 m /day. Current compensation is 96%,
accumulated—89%. The current recovery factor is 0.483, with a water cut of 98.7%. Maps
accumulated—89%. The current recovery factor is 0.483, with a water cut of 98.7%. Maps
of the current state of development and accumulated withdrawals for object I are shown
in Figure 9C,D.
4.2. Horizon Object II—Kumkol Field
Polymers 2025, 17, 829
The development system is a 9-point area impact system, with a distance between
15 of 26
wells of 250 m. The dynamics of the main development indicators are presented in Figure
10A,B.
of theSince
current
of development
and accumulated
withdrawals
I are produced
shown in
thestate
beginning
of development,
18,802 thousand
tons offor
oil object
have been
3
Figure
9C,D.
at the site, or 74.3% of the reserve. A total of 108,412 thousand m of water has been
injected into the formations. The current oil flow rate is 3.4 tons/day, liquid—170.8
4.2. Horizon Object II—Kumkol Field 3
tons/day. Well injectivity is 338.8 m /day. Current compensation is 93%, accumulated—
system isfactor
a 9-point
area with
impact
system,
with
a distance
wells
92%.The
Thedevelopment
current oil recovery
is 0.455,
water
cut of
97.9%.
Mapsbetween
of the current
of
250
m.
The
dynamics
of
the
main
development
indicators
are
presented
in
Figure
10A,B.
state of development and accumulated selections for object II are shown in Figure 10C,D.
Figure
accumulated selections.
Figure 10.
10. (A,B)
(A,B) Dynamics
Dynamics of
of the
the main
main development
development indicators.
indicators. (C)
(C) Map
Map of
of accumulated
selections.
(D)
Map
of
current
selections
for
Object
II
in
the
Kumkol
Field.
(D) Map of current selections for Object II in the Kumkol Field.
Since the beginning of development, 18,802 thousand tons of oil have been produced
at the site, or 74.3% of the reserve. A total of 108,412 thousand m3 of water has been injected
into the formations. The current oil flow rate is 3.4 tons/day, liquid—170.8 tons/day.
Well injectivity is 338.8 m3 /day. Current compensation is 93%, accumulated—92%. The
4.3. Horizon Object III—Kumkol Field
Polymers 2025, 17, 829
The development system is a 9-point area impact system, with a distance between
16 of 26
wells of 250 m. The dynamics of the main development indicators are presented in Figure
11A,B.
Since
beginning
9209cutthousand
ofofoil,
88.9% state
of the
current
oil the
recovery
factorofis development,
0.455, with water
of 97.9%.tons
Maps
theorcurrent
of
reserve,
has been
at the
site. A for
total
of 73.579
m3 of water
development
and produced
accumulated
selections
object
II are thousand
shown in Figure
10C,D.has been
injected into the formations. The current oil flow rate is 4.1 tons/day, liquid—363.3
4.3. Horizon
Object
III—Kumkol
Field
tons/day.
Well
injectivity
is 554.1
m3/day. Current compensation is 138%, accumulated—
system is
a 9-point
areawith
impact
system,
with
a distance
between
wells
98%. The
The development
current oil recovery
factor
is 0.527,
water
cut of
98.8%.
Maps of
the current
of 250ofm.
The dynamics
the main development
indicators
areare
presented
in Figure
Figure 11C,D.
11A,B.
state
development
andofaccumulated
withdrawals
for site III
shown in
Figure 11. (A,B) Dynamics of the main development indicators. (C) Map of accumulated selections.
(D) Map of current selections for Object III in the Kumkol Field.
Figure 11. (A,B) Dynamics of the main development indicators. (C) Map of accumulated selections.
(D) Map
of current
selections
Object III in the
Kumkol
Field.
Since
the beginning
offor
development,
9209
thousand
tons of oil, or 88.9% of the reserve,
has been produced at the site. A total of 73.579 thousand m3 of water has been injected
into the formations. The current oil flow rate is 4.1 tons/day, liquid—363.3 tons/day.
Well injectivity is 554.1 m3 /day. Current compensation is 138%, accumulated—98%. The
current oil recovery factor is 0.527, with water cut of 98.8%. Maps of the current state of
development and accumulated withdrawals for site III are shown in Figure 11C,D.
4.4. Horizon Object IV—Kumkol Field
Polymers 2025, 17, 829
The development system is a natural regime with selective placement of wells. The
17 of 26
distance between wells is 500 m. The dynamics of the main development indicators are
presented in Figure 12A,B.
Since the
beginning
of development,
223 thousand tons of oil, or 77.4% of the reserve,
4.4. Horizon
Object
IV—Kumkol
Field
has been produced at the facility. The current oil flow rate is 1.4 tons/day, liquid—133.3
The development system is a natural regime with selective placement of wells. The
tons/day. Current compensation is 0%, accumulated—24%. The current recovery factor is
distance between wells is 500 m. The dynamics of the main development indicators are
0.326, with a water cut of 98.6%. Maps of the current state of development and
presented in Figure 12A,B.
accumulated withdrawals for facility IV are shown in Figure 12C,D.
Figure 12.
12. (A,B)
(A,B) Dynamics
Dynamics of
of the
the main
main development
development indicators.
indicators. (C)
(C) Map
Map of
of accumulated
selections.
Figure
accumulated selections.
(D) Map
Mapof
ofcurrent
currentselections
selectionsfor
forObject
ObjectIV
IVin
inthe
theKumkol
KumkolField.
Field.
(D)
Since
the beginning
of development,
223 thousand
of oil,
77.4%
of the
The observed
difference
in retention factors
betweentons
Horizon
IIIor
and
Horizon
IVreis
serve,
has
been
produced
at
the
facility.
The
current
oil
flow
rate
is
1.4
tons/day,
liquid—
primarily due to variations in reservoir properties. Horizon III exhibits higher
133.3
tons/day.
Current
0%, accumulated—24%.
current
recovery
permeability
(634
mD) compensation
and porosity is
(23%),
allowing for betterThe
fluid
retention
and
factor is 0.326, with a water cut of 98.6%. Maps of the current state of development and
accumulated withdrawals for facility IV are shown in Figure 12C,D.
The observed difference in retention factors between Horizon III and Horizon IV is
primarily due to variations in reservoir properties. Horizon III exhibits higher permeability
Polymers2025,
2025,17,
17,x 829
Polymers
FOR PEER REVIEW
19 18
of of
2826
(634 mD) andefficiency.
porosity (23%),
allowing
for better
fluid
retention and
displacement
efficiency.
displacement
In contrast,
Horizon
IV has
significantly
lower
permeability
(145
In
contrast,
Horizon
IV
has
significantly
lower
permeability
(145
mD)
and
porosity
(21.5%),
mD) and porosity (21.5%), leading to reduced oil retention and increased water
leading to reduced
oil retention
and increased
water
encroachment.
structural
encroachment.
Additionally,
structural
differences
contribute
to thisAdditionally,
variation, as Horizon
differences
contribute
to
this
variation,
as
Horizon
IV
is
located
in
a
lower
structural
zone,
IV is located in a lower structural zone, making it more prone to water influx from
making it more
prone to water influx from underlying aquifers.
underlying
aquifers.
4.5. Horizon Object I—East Kumkol Field
4.5. Horizon Object I—East Kumkol Field
The development system is a natural depletion regime with a well spacing
The development system is a natural depletion regime with a well spacing (400 × 400
(400 × 400 m). The dynamics of the main development indicators are presented in
m). The dynamics of the main development indicators are presented in Figure 13A,B.
Figure 13A,B. Since the beginning of development, 308 thousand tons of oil have been proSince the beginning of development, 308 thousand tons of oil have been produced at the
duced at the facility, or 101% of the reserve. The accumulated liquid production amounted
facility, or 101% of the reserve. The accumulated liquid production amounted to 3331
to 3331 thousand tons. The current recovery factor is 0.495, with a water cut of 96.7%. The
thousand tons. The current recovery factor is 0.495, with a water cut of 96.7%. The current
current oil flow rate is 6.1 tons/day, liquid—196.2 tons/day.
oil flow rate is 6.1 tons/day, liquid—196.2 tons/day.
Figure 13. (A,B) Dynamics of the main development indicators, (C) Map of accumulated selections.
Figure 13. (A,B) Dynamics of the main development indicators, (C) Map of accumulated selections.
(D) Map of current selections for Object I in the East Kumkol Field.
(D) Map of current selections for Object I in the East Kumkol Field.
As
be seen
seenfrom
from
Figure
13A,B,
oil production
decreased
2013,is which
is
Ascan
can be
Figure
13A,B,
oil production
decreased
in 2013,inwhich
associated
associated
with
an
increase
in
water
cut
from
74%
to
91%.
Maps
of
the
current
state
of
with an increase in water cut from 74% to 91%. Maps of the current state of development
development
and accumulated
production
forshown
object in
I are
shown
in Figure 13C,D.
and accumulated
production for
object I are
Figure
13C,D.
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x FOR PEER REVIEW
Polymers
20 of 28
19 of 26
4.6. Horizon Object II—East Kumkol Field
The development system is a marginal flooding system with a distance between wells
Thedynamics
dynamics of
ofthe
themain
maindevelopment
developmentindicators
indicatorsare
arepresented
presented in
inFigure
Figure14A,B.
14A,B.
of 400 m. The
Since the start of development, 1289 thousand tons of oil, or 75.1% of the reserve, has been
produced
total
of 6023
thousand
m3 of
has been
into the
formaproduced at
atthe
thesite.
site.AA
total
of 6023
thousand
m3water
of water
has injected
been injected
into
the
tions. Current
oil flowoilrates
arerates
4.0 tons/day,
liquid—86.3
tons/day, tons/day,
and well injectivity
formations.
Current
flow
are 4.0 tons/day,
liquid—86.3
and well
is 217.2 m3is
/day.
is 65.2%, accumulated—76.7%.
The currentThe
oil
injectivity
217.2Current
m3/day.compensation
Current compensation
is 65.2%, accumulated—76.7%.
recovery
factor
is
0.310,
with
water
cut
of
94.9%.
Maps
of
the
current
development
status
current oil recovery factor is 0.310, with water cut of 94.9%. Maps of the current
and accumulated
production
are shown
in Figure are
14C,D.
development
status
and accumulated
production
shown in Figure 14C,D.
Figure
Figure 14.
14. (A,B)
(A,B) Dynamics
Dynamics of
of the
the main
main development
development indicators.
indicators. (C)
(C) Map
Map of
of accumulated
accumulated selections.
selections.
(D)
Map
of
current
selections
for
Object
II
in
the
East
Kumkol
Field.
(D) Map of current selections for Object II in the East Kumkol Field.
production at
atthe
theasset
assetamounted
amountedtoto552.2
552.2thousand
thousand
tons
2017.
Cumulative
Oil production
tons
in in
2017.
Cumulative
oil
oil production
at both
fields
43,200.0thousand
thousandtons,
tons,oror79.6%
79.6%of
of the
the initial
initial recoverable
production
at both
fields
is is
43,200.0
reserves, with a water cut of 98.4%. The availability of industrial category reserves within
the licenses at the 2017 production level is 20 years. Over the past 5 years, the number of
Polymers 2025, 17, x FOR PEER REVIEW
Polymers 2025, 17, 829
21 of 28
20 of 26
operating production wells has decreased by 123 units due to the transfer of wells to the
fund for
for injection
injectionand
andcontrol
controland
andobservation
observationwells
wells
monitor
energy
state
inactive fund
toto
monitor
thethe
energy
state
of
of deposits.
reasons
inactivity
of production
are unprofitable
low unprofitable
flow
deposits.
TheThe
reasons
for for
the the
inactivity
of production
wellswells
are low
flow rates
rateshigh
andwater
high cuts
water
cutsproduct.
of the The
product.
Theoperating
fund forinjection
operating
injection
wells has
and
of the
fund for
wells
has decreased
by
9decreased
units dueby
to 9the
transfer
ofthe
wells
to theof
inactive
fund.
units
due to
transfer
wells to
the inactive fund.
4.7.
Well Interventions
4.7. Well
Interventions for
for Kumkol
Kumkol Field
Field
The
The proposed
proposed and
and conducted
conducted main
main types
types for
for the
the well
well interventions
interventions in
in this
this study
study
include
optimization,
optimizing
well
operating
modes,
various
perforation
methods
(such
include optimization, optimizing well operating modes, various perforation methods
as
additional
perforations,
re-perforations,
and inclusions),
transferring
wells to different
(such
as additional
perforations,
re-perforations,
and inclusions),
transferring
wells to
sites,
the
bottom
hole
zone
treatment,
and
performing
hydraulic
fracturing.
Over the 5 years
different sites, the bottom hole zone treatment, and performing hydraulic fracturing.
Over
of
the
simulation,
132
events
have
been
completed
to
optimize
the
well
operating
mode,
of
the 5 years of the simulation, 132 events have been completed to optimize the well
which
127
wells
were
operated
with
a
positive
effect.
At
the
same
time,
a
gradual
decrease
operating mode, of which 127 wells were operated with a positive effect. At the same time,
in
the efficiency
of this
type
is noted—the
increase in oil
flow rate
decreased
a gradual
decrease
in the
efficiency
of thisaverage
type is noted—the
average
increase
in oil over
flow
this
period
from
7.2
tons/day
(2013)
to
1.9
tons/day
(2017).
On
average,
for
2013–2017,
the
rate decreased over this period from 7.2 tons/day (2013) to 1.9 tons/day (2017). On average,
increase
in oil was
6 tons/day
(Figure
for Kumkol
Field).
for 2013–2017,
the increase
in oil
was 615
tons/day
(Figure
15 for Kumkol Field).
Figure 15. Well interventions for Kumkol Field between 2013 and 2017.
Figure 15. Well interventions for Kumkol Field between 2013 and 2017.
Concerning operational
operational facilities,
facilities, the
the well
Concerning
well optimization
optimization is
is consistent
consistent across
across the
the board,
board,
with
the
average
increase
in
oil
flow
rate
ranging
from
5.3
to
6.4
tons
per
day,
depending
with the average increase in oil flow rate ranging from 5.3 to 6.4 tons per day, depending on
on horizon
the horizon
(Figure
15). 16A
Figure
16A illustrates
the dynamics
successfulofdynamics
of well
the
(Figure
15). Figure
illustrates
the successful
well optimization
optimization
inField.
the Kumkol
Field.
However,
there is adecline
noticeable
decline
across
operations
in operations
the Kumkol
However,
there
is a noticeable
across
all facilities
all
facilities
related
to
the
perforation
method,
as
depicted
in
Figure
16B
for
the
Kumkol
related to the perforation method, as depicted in Figure 16B for the Kumkol Field. The
Field. The maximum
in rate
oil flow
rate according
well transfers
to another
maximum
increase inincrease
oil flow
according
to well to
transfers
to another
objectobject
over
over
the
5
years
is
observed
at
development
horizon
I
and
amounts
to
10.8
tons/day.
The
the 5 years is observed at development horizon I and amounts to 10.8 tons/day. The
increase in
in oil
oil flow
flow rate
rate at
at development
development horizon
horizon II
II amounted
amounted to
to 9.8
9.8 tons/day,
tons/day, at
at horizon
horizon
increase
III—8.4
tons/day,
and
at
Horizon
IV—3.5
tons/day
(Figures
15
and
16C).
Figure
16C
III—8.4 tons/day, and at Horizon IV—3.5 tons/day (Figures 15 and 16C). Figure 16C shows
shows
the
dynamics
of
successful
operations
on
transfers
to
another
horizon.
The
effectiveness
the dynamics of successful operations on transfers to another horizon. The effectiveness of
of the
event
is decreasing.
the
event
is decreasing.
It should
should be
be noted
noted that,
that, based
based on
on the
the magnitude
magnitude of
of the
the increase
increase in
in oil
oil flow
flow rate,
rate, this
this
It
type
of
well
intervention
is
the
most
effective
in
the
conditions
of
the
Kumkol
Field.
type of well intervention is the most effective in the conditions of the Kumkol Field.
Polymers
FOR PEER REVIEW
Polymers 2025,
2025, 17,
17, x829
2221ofof 28
26
Figure
ofof
objects
between
2013
and
2017,
1. The
Kumkol
FieldField
for (A)
Figure 16.
16.The
Thesuccessful
successfuldynamics
dynamics
objects
between
2013
and
2017,
1. The
Kumkol
for
well
optimization
operations,
(B) perforation
methods,methods,
(C) transfer
to transfer
another object
II. Theobject
East Kumkol
(A) well
optimization
operations,
(B) perforation
(C)
to another
II. The
East for
Kumkol
Field
for (D) well
optimization
operations,
(E) perforation
transfer to
Field
(D) well
optimization
operations,
(E) perforation
methods,
(F) transfermethods,
to another(F)
object.
another object.
4.8. Well Interventions for East Kumkol Field
4.8. Well Interventions for East Kumkol Field
Over the past 5 years, the primary types of well interventions implemented in the
Over the past 5 years, the primary types of well interventions implemented in the
field include the optimization of well operating modes, various perforation methods (such
field include the optimization of well operating modes, various perforation methods (such
as additional perforations, re-perforations, and inclusions), transferring wells to different
as additional perforations, re-perforations, and inclusions), transferring wells to different
sites, the bottom hole zone treatment, and performing hydraulic fracturing. Forty-seven
sites, the bottom hole zone treatment, and performing hydraulic fracturing. Forty-seven
successful operations were analyzed to assess the effectiveness of measures for increasing
successful operations were analyzed to assess the effectiveness of measures for increasing
oil production between 2013 and 2017. The primary types of well interventions during
oil production between 2013 and 2017. The primary types of well interventions during this
this period included perforation methods (43%), treatment of the bottom hole zone (23%),
period included perforation methods (43%), treatment of the bottom hole zone (23%), and
and optimization of well operating modes (19%) (Figure 17).
optimization of well operating modes (19%) (Figure 17).
During the analyzed period, the operating mode of nine wells in the field was optimized, resulting in positive outcomes for all of them. The average increase in oil flow rate
decreased to five tons per day in 2016. Over the period from 2013 to 2017, the average
increase was 6.7 tons per day. Concerning specific operational objects, the highest increase
in oil flow rate due to well optimization occurred at horizon II, with an increase of 6.9 tons
per day. Meanwhile, the increase in flow rate at the development horizon was five tons per
day. Figure 16D illustrates the trends in successful well optimization operations.
The highest increase in oil flow rate observed from the perforation methods over the
simulated years was for horizon II, reaching 6.3 tons per day. In contrast, horizon I had an
Polymers 2025, 17, 829
22 of 26
increase of 2.1 tons per day. Figure 16E illustrates the dynamics of successful operations
using perforation methods, showing a noticeable decline in the operation’s effectiveness
over time. Four transfers to another horizon were carried out during the analyzed period,
resulting in an increase of 6.8 tons per day in the average oil flow rate. Figure 16F23shows
Polymers 2025, 17, x FOR PEER REVIEW
of 28
the dynamics of successful operations for these transfers.
Figure 17. Well interventions for East Kumkol Field between 2013 and 2017.
Figure 17. Well interventions for East Kumkol Field between 2013 and 2017.
During theand
analyzed
period, theFeasibility
operating mode
of nine wells
in the field was
5. Economic
Technological
of Polymer
Flooding
optimized, resulting in positive outcomes for all of them. The average increase in oil flow
To objectively assess the economic viability of various enhanced oil recovery (EOR)
rate decreased to five tons per day in 2016. Over the period from 2013 to 2017, the average
methods, a comparative cost-benefit analysis was conducted. This evaluation considered
increase was 6.7 tons per day. Concerning specific operational objects, the highest increase
both capital expenditures (CAPEX) and operational expenditures (OPEX) associated with
in oil flow rate due to well optimization occurred at horizon II, with an increase of 6.9 tons
different water cut management strategies, including traditional mechanical methods and
per day. Meanwhile, the increase in flow rate at the development horizon was five tons
polymer flooding. The results, summarized in Table 14, provide a direct comparison of
per day. Figure 16D illustrates the trends in successful well optimization operations.
the cost per cubic meter of oil produced and the corresponding increase in oil recovery for
The highest increase in oil flow rate observed from the perforation methods over the
each method.
simulated years was for horizon II, reaching 6.3 tons per day. In contrast, horizon I had
an
increase
of 2.1 tonscost
peranalysis
day. Figure
16E illustrates
the
of successful operations
Table
14. Comparative
of traditional
methods
vs.dynamics
polymer flooding.
using perforation methods, showing a noticeable decline in the operation’s effectiveness
Average Increase in Oil
Method
Costhorizon
($/m3 of were
Oil Produced)
over time. Four
transfers to another
carried out during Recovery
the analyzed
period,
(%)
resulting in an increase of 6.8 tons per day in the average oil flow rate. Figure 16F shows
Hydraulic Fracturing (HF)
20–30
5–10
the dynamics of successful operations for these transfers.
Water Shut-off Treatments
15–25
8–12
Polymer Flooding
10–15
15–20
5. Economic
and Technological Feasibility
of Polymer Flooding
To objectively assess the economic viability of various enhanced oil recovery (EOR)
The data
indicate that
polymer flooding
the most cost-effective
solution,
delivermethods,
a comparative
cost-benefit
analysisoffers
was conducted.
This evaluation
considered
ing acapital
higherexpenditures
oil recovery rate
at a lower
cost per cubic
meter compared
toassociated
both hydraulic
both
(CAPEX)
and operational
expenditures
(OPEX)
with
fracturing
(HF)
and
water
shut-off
treatments.
different water cut management strategies, including traditional mechanical methods and
Unlike
hydraulic
which involves
high initial
costs and
is often
less effective
polymer
flooding.
Thefracturing,
results, summarized
in Table
14, provide
a direct
comparison
of
in
reservoirs
with
advanced
water
breakthrough,
polymer
flooding
provides
a more conthe cost per cubic meter of oil produced and the corresponding increase in oil recovery
for
trolled
displacement process, improving sweep efficiency and delaying water breakthrough.
each
method.
Polymers 2025, 17, 829
23 of 26
Similarly, while water shut-off treatments can temporarily mitigate excessive water production, they do not provide long-term improvements in oil displacement efficiency.
By enhancing mobility control and increasing the volumetric sweep efficiency, polymer
flooding achieves a more sustainable oil production rate while minimizing operational
costs. This makes it a highly attractive EOR strategy for mature fields like Kumkol, where
the high water cut (98.4%) necessitates an efficient method to improve oil displacement
while maintaining economic feasibility.
In addition to technical advantages, the return on investment (ROI) for polymer
flooding is significantly higher than that of alternative methods, given its lower cost per
unit of oil recovered and long-term operational benefits. The ability to reduce excessive
water production and extend the productive life of the reservoir further supports the
economic feasibility of implementing polymer flooding in the Kumkol Field.
6. Conclusions
The study highlights the critical challenges posed by high water cut in the mature
reservoirs of the Kumkol and East Kumkol fields, where water saturation exceeds 98% in
several productive horizons. Traditional water shut-off methods and well interventions
have demonstrated limited efficiency in mitigating excessive water production, necessitating the implementation of advanced chemical-enhanced oil recovery (EOR) techniques,
particularly polymer flooding.
Hydrodynamic modeling and experimental results confirm that polymer flooding is
the most viable method for enhancing oil recovery in high-water-cut reservoirs. Laboratory
studies indicate that the optimal polymer concentration lies within the 0.15–0.20% range
(previously expressed as 1500–2000 ppm), providing a 15–20% increase in the oil displacement factor while effectively controlling water mobility. Furthermore, numerical
simulations demonstrate that temperature stability is a key factor, as polymer viscosity
declines significantly at temperatures above 60 ◦ C, necessitating the selection of thermally
stable polymer formulations.
The comparative cost analysis further supports the economic feasibility of polymer
flooding. Unlike hydraulic fracturing and water shut-off treatments, polymer flooding
exhibits a superior balance between cost and oil recovery efficiency, delivering higher
incremental recovery at a lower cost per cubic meter of produced oil. Given the high
water cut and the declining efficiency of traditional well interventions, polymer flooding
presents a technically and economically justified solution for maximizing oil recovery in
mature reservoirs.
Strategic Implications and Recommendations
1.
2.
3.
4.
Implementation of polymer flooding as the primary EOR strategy in high-water-cut
reservoirs to improve mobility control and enhance sweep efficiency.
Optimization of polymer selection based on formation temperature, water salinity,
and polymer rheology to ensure long-term stability and efficiency.
Integration of polymer flooding with existing water management strategies to minimize water production and extend the economic life of the reservoir.
Continued monitoring and numerical modeling to evaluate the long-term performance of polymer flooding and adjust injection strategies accordingly.
In conclusion, polymer flooding represents the most effective and sustainable method
for mitigating excessive water production and enhancing oil recovery in the Kumkol and
East Kumkol fields. The findings of this study provide a strong technical and economic
foundation for the large-scale deployment of polymer-based EOR solutions in Kazakhstan’s
mature oil fields.
Polymers 2025, 17, 829
24 of 26
Author Contributions: Methodology, M.Z.; Resources, A.D.; Data curation, Z.N.; Writing—original
draft, Z.A., A.N.A.-D. and N.T.; Visualization, G.B.; Funding acquisition, K.N. All authors have read
and agreed to the published version of the manuscript.
Funding: This research was funded by the Committee of Science of the Ministry of Science and Higher
Education of the Republic of Kazakhstan Grant number BR24992809 titled “Obtaining new chemical
reagents for the extraction, preparation, and transportation of paraffin oil using local raw materials”.
Institutional Review Board Statement: Not applicable.
Data Availability Statement: The original contributions presented in this study are included in the
article. Further inquiries can be directed to the corresponding author.
Conflicts of Interest: The authors declare no conflict of interest.
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