Current Issue
Scientific Petroleum 2025, 2
GEOLOGY, GEOPHYSICS & FORMATION EVALUATION
H. I. Shakarov,
M. A. Bakirov, N. H. Mehdiyeva, A. Q. Bakirova,
A. E. Abdullayeva «OilGasScientificResearchProject» Institute, SOCAR, Baku, Azerbaijan
Geophysics and Geology Department,
SOCAR, Baku,Azerbaijan |
The article substantiates the necessity of taking into account the
variations of geophysical and geochemical fields under the influence of
geodynamic processes during the analysis of well geophysical survey (WGS) data.
Studies conducted at numerous research polygons around the world have
thoroughly examined the variations in the Earth's natural electric and
geomagnetic fields prior to earthquakes. Analysis of the obtained results has
shown that changes in the Earth's geomagnetic and natural electric fields, as
well as in the electrical resistivity of rocks, are observed both before and
after earthquakes. Considering these indicators, during the reanalysis of well
geophysical survey data from certain fields located on the Absheron Peninsula,
the influence of geodynamic processes and variations in geophysical and
geochemical fields on the evaluation of reservoir oil and gas content has been
determined. In order to identify the impact of geodynamic processes on well
geophysical survey data, a catalog of earthquakes felt on the Absheron
Peninsula and adjacent areas was compiled. Based on this catalog, an epicenter
map of earthquakes expected to be observed within the studied fields was
created. The WGS materials from wells drilled during «active» and
«quiet» seismic periods were comparatively
analyzed, the main layer parameters were recalculated, and the influence of
geodynamic activity was substantiated. The research results have shown that the
proper consideration of geodynamic processes ensures high accuracy and
reliability in the exploration and exploitation of oil and gas fields. At the
same time, the obtained results indicate that the assessment of geodynamic
processes directly affects not only geophysical parameters but also geochemical
indicatorse to the closure of the Tethys Ocean at the end of the Cretaceous and
beginning of the Paleogene.
Keywords: geodynamic processes; seismic activity;
earthquake–production relationship; hydrocarbon-bearing reservoirs; geochemical
fields; geophysical field variations; borehole geophysical investigations; well
log analysis; electrical resistivity.
*e-mail: hafiz.shekerov@socar.az
Date submitted: 14.10.2025 Date accepted: 06.11.2025 |
S. H. Jafarov
Baku State University, Baku,
Azerbaijan
AzerGold, Baku,
Azerbaijan |
The article is devoted to the petrogeochemical features of Jurassic
volcanic rocks of the Chovdar ore field of the Lesser Caucasus based on 94
silicate and 36 trace element analyses from various volcanic rock samples
within the ore field. The data reveal a diverse range of lithologies; including
basaltic; andesitic; dacitic; and rhyolitic compositions; predominantly of
calc-alkaline and tholeiitic affinity. Diagrams such as TAS; AFM; and tectonic
discrimination plots confirm the subduction-related magmatic setting and
suggest a mature island arc environment with complex magmatic differentiation.
The interpretation of the spider diagram shows that the studied samples were
formed from magma formed under subduction conditions; enriched with
volatile-transported elements; and formed under conditions that underwent a
significant period of crustal development; which; as mentioned earlier; is
consistent with the formation of the Lesser Caucasus metallogenic province;
Lok-Karabakh structural formation zone under the conditions of island arc
volcanism. The presence of both low-K mafic and calc-alkaline felsic rocks
reflects multi-stage magmatism linked to extensional tectonics and mantle
metasomatism. The trace element data further corroborates subduction-derived
magma evolution; characterized by HFSE depletion and LILE enrichment. These
findings collectively indicate that the Chovdar ore field evolved under
sustained arc volcanism; with implications for regional metallogenies in the
Lesser Caucasus. Geochemical differences between the Lower and Upper Bajocian
units reveal a transition from early tholeiitic to later calc-alkaline
magmatism; indicative of changing mantle source characteristics and increasing
crustal interaction. The coexistence of low-K basaltic and high-silica
dacitic-rhyolitic rocks implies polyphase magmatism and mantle-crust mixing.
Overall; the results point to an island arc regime with active subduction;
mantle wedge metasomatism; and multi-stage magmatic evolution contributing to
the mineralization and alteration processes within the Chovdar ore field.
Keywords: Chovdar ore field; Lesser Caucasus; petrogeochemical characteristics; TAS
diagram; spider diagram; geochemical analyses; rare earth and trace elements;
tectonic discrimination and spyder diagram.
e-mail: ceferovsoltan@gmail.com
Date submitted:
22.08.2025 Date accepted:
10.12.2025 |
|
M. F. Tagiyev,
O. V. Rajabli
«OilGasScientificResearchProject»
Institute, SOCAR, Baku, Azerbaijan |
The amount of organic carbon in sediments within the Ganja petroliferous
region has been investigated based on various sources of data. The Ganja region
is located at the southwesternmost margin of the Yevlakh-Aghjabedi Basin and
occupies the southeastern part of the Lesser Caucasus monocline. The
Mesozoic–Cenozoic sedimentary pile has an average thickness of approximately 8
km. The Mesozoic surface dips northeastward to depths of approximately 4-5 km.
The region exhibits interformational and intraformational unconformities, along
with structural discordances between the Mesozoic, Paleogene-Miocene, and
Pliocene stratigraphic complexes. Throughout most of the Ganja region drilling
reported predominantly shaly Paleogene–Miocene strata with infrequent
sandy-silty and carbonate interlayers. These units are proven to be
commercially productive in the Gazanbulag, Ajidara, Naftalan, and Terter
fields, where oil accumulations occur within sandy reservoirs of Eocene and
Oligocene–Miocene age. Among different age sedimentary units, the Maykop and
Eocene formations are distinguished by their relatively higher organic carbon
contents. In the study reports of earlier years distribution of the Corg in the
Eocene sediments is represented by minimum, mean and maximum values. To
maximize the value of these borehole core based analytical evidences we turned
to statistical study techniques. Taking into consideration available
min-average-max values synthetic random datasets were generated, their
conformity to logarithmic theoretical distribution evaluated, and statistical
tests performed. Using the nonparametric Kruskal-Wallis test a hypothesis on
affiliation of the studied localities to a common geochemical population was
examined, and the differences revealed interpreted. The organic-geochemical
variability trend was determined, thereby providing the input structure for
further basin analysis.
Keywords: organic carbon in
sediments; Eocene; the Ganja petroliferous region; logarithmic
distribution; statistical test..
*e-mail: orkhan.rajabli@socar.az
Date submitted:
27.11.2025 Date accepted:
12.12.2025 |
RESERVOIR ENGINEERING
Stabilization of
unstable reservoirs in oil fields of Azerbaijan: potential and
prospects of copolymer-based methods
F. F. Ahmed,
A. H. Gayibova, M. A. Huseynov
«OilGasScientificResearchProject»
Institute, SOCAR, Baku, Azerbaijan
Scientific
Research Institute «Geotechnological Problems of Oil, Gas, and Chemistry» |
This research focuses on the application of copolymer technologies for
stabilizing unstable oil reservoirs, with particular attention to the oil
fields in Azerbaijan. Unstable reservoirs, characterized by weakly consolidated
sandstone formations, often experience sand production and formation damage,
which significantly reduce well productivity and complicate extraction
processes. The study explores how copolymers-synthetic polymers composed of two
or more different monomers—can be used to enhance the mechanical stability of
reservoir rocks by forming flexible, durable films within the porous matrix.
These films help to bind loose particles and reduce sand influx while maintaining
sufficient permeability for oil flow. A comprehensive SWOT analysis is
presented to assess the advantages and limitations of copolymer stabilization
in oil reservoirs. Strengths include the polymers’ resistance to thermal
degradation and chemical attack in harsh reservoir environments, the ability to
tailor polymer properties to specific geological conditions, and the potential
for increased oil recovery through improved reservoir conformance. However,
challenges such as the complexity of polymer formulations, potential
injectivity issues, environmental concerns related to polymer degradation
products, and higher initial costs are also discussed. Recommendations for
pilot-scale testing and gradual field deployment in Azerbaijan’s oil sector are
outlined, highlighting the need for rigorous laboratory characterization,
reservoir simulation, and real-time monitoring to optimize copolymer treatment
design. The research concludes that copolymer technologies represent a
promising and sustainable approach to mitigating sand production, improving
well integrity, and boosting overall oil recovery, thereby contributing to the
efficient development of Azerbaijan’s hydrocarbon resources.
KEYWORDS: copolymer technologies; reservoir stabilization; unstable
oil reservoirs; enhanced oil recovery; polymer flooding; sand control;
Azerbaijan oil fields; gel formation; nanostructured polymers;
stimuli-responsive polymers; oil production optimization; reservoir
permeability.
*e-mail: fariz.ehmed@socar.az
Date submitted: 14.10.2025
Date accepted: 10.12.2025 |
PRODUCTION & OPERATIONS
|
Sh. P. Kazimov,
L. G. Hajikarimova, E. S. Abdullayeva, E. Sh.Azimova
Azerbaijan State
Oil and Industry University, Baku, Azerbaijan
«OilGasScientificResearchProject»
Institute, SOCAR, Baku, Azerbaijan |
The method of operating wells with rod-type deep well pumps is widely
used in the final stage of oil field development. In a group of
low-liquid-level wells operated with rod-type submersible pumps, delays occur
in the operation of the intake valve and complete filling of the pump cylinder
is not achieved. In wells with low liquid levels, since the pump cylinders are
not completely filled with liquid, the plunger hits the lower part of the
cylinder during the downward movement of the plunger, which causes premature
pump failure. On the other hand, in wells with sand formations and low liquid
levels, the pump intake is exposed to the active influence of mechanical
impurities. A constructive solution has been developed to overcome the above
problems. Based on the developed constructive solution, the pump intake valve
is opened and closed and the pump cylinder is filled regardless of the dynamic
level of the liquid in the well. The problem of the pump cylinder not being
completely filled, the plunger hitting the cylinder, and the intensive wear of
the pump intake part due to the influence of mechanical mixtures are prevented.
As a result of the introduction of the new pump, it is possible to improve the
filling of the pump with liquid in wells with low liquid levels. Delays in
opening and closing valves are eliminated. The newly developed pump design
prevents the pump's intake valves from quickly failing due to mechanical
impurities. By eliminating pump idling, the application of the new pump design
in wells with low liquid levels results in increased well production. As a
result of the introduction of a new pump design, the service life of the pumps
is increased and the TAM is increased.
Keywords: well; pump; plunger; cylinder;
hydraulic shock; dynamic liquid level; mechanical mixtures; intake valve.
*e-mail: elmira.s.abdullayeva@socar.az
|
|
S. A. Isayeva
Azerbaijan State
Oil and Industry University, Baku, Azerbaijan |
Ensuring rock stability is of paramount importance for the efficient,
safe, and long-term operation of underground gas storages. One of the most
critical challenges affecting well integrity in unconsolidated or weakly
cemented sandstone formations is sand manifestation, which includes sand
production, influx, and migration. Such phenomena compromise the mechanical and
technological stability of gas wells, leading to increased operational risks,
equipment damage, and significant economic losses. In Azerbaijan, sand-related
issues have been particularly observed in the Garadagh and Kalmas underground
gas storage facilities, where uncontrolled sand migration poses a substantial
threat to operational reliability and reservoir performance. This study
presents a comprehensive geotechnical analysis of sand migration under unstable
rock conditions, focusing on the mechanisms of sand mobilization and transport
within poorly consolidated formations. The limitations of conventional
mechanical sand control methods, such as gravel packs, sand screens, and other
filtration systems, have been critically evaluated. Despite their widespread
use, these techniques often fail to provide long-term stability under
challenging subsurface conditions, necessitating alternative solutions. A
location-specific, integrated approach has been scientifically substantiated
for application in the Garadagh and Kalmas gas storages, combining selective
chemical injection techniques with continuous monitoring programs to detect
early signs of sand mobilization. The results demonstrate that managing sand
risk in unconsolidated formations requires tailored technological strategies
that account for reservoir heterogeneity, formation properties, and operational
conditions. Chemical consolidation technologies, in particular, show high
potential to significantly improve mechanical stability, reduce operational
risks, and extend the productive life of gas wells in these storage facilities.
In conclusion, this study underscores the importance of combining advanced
geotechnical analysis, innovative chemical consolidation methods, and
continuous monitoring to ensure safe, reliable, and economically efficient
operation of underground gas storages in regions prone to sand-related
challenges.
Keywords: sand production; chemical
consolidation; underground gas storages; unconsolidated rocks; nanotechnology;
MICP (Microbial-Induced Carbonate Precipitation); Garadagh; Kalmas; polymer
systems; gas well stability.
e-mail: sevil.isayeva@asoiu.edu.az
Date submitted: 04.11.2025
Date accepted: 18.12.2025 |
|
F. F. Ahmed,
S. I. Mansurova, M. A. Rzayeva
1«OilGasScientificResearchProject»
İnstitute, SOCAR, Baku, Azerbaijan
2Azerbaijan State
Oil and Industry University, Baku, Azerbaijan |
Mature oil fields in Azerbaijan face significant production decline,
high water cut, and operational challenges in late-stage development. A primary
factor limiting oil recovery is the uncontrolled influx of water through
behind-the-casing flows, often caused by deteriorated cement sheaths, casing
defects, or intersecting natural fractures. These flows lead to premature water
breakthrough, disrupt injectivity profiles, and reduce waterflooding
efficiency, making effective isolation crucial for extending well life and
maximizing hydrocarbon recovery. This study investigates the use of expanding
cement slurry as an innovative solution for isolating behind-the-casing flows.
The slurry is designed to expand volumetrically after setting, forming a tight
bond with the casing and surrounding formation. This property allows it to fill
micro-annuli, cracks, and channels in degraded cement sheaths, creating a
durable hydraulic seal where conventional cement often fails. Laboratory
experiments and field applications were conducted to evaluate the slurry under
varying downhole conditions, including high water cut, temperature
fluctuations, and differential pressures. Results demonstrate that expanding
cement significantly reduces water inflow, stabilizes well pressure profiles,
and enhances oil recovery efficiency during late-stage waterflooding.
Implementation of this technology also decreases the frequency of remedial
interventions, reduces operational costs, and improves overall reservoir
management by promoting more uniform oil displacement. Practical guidelines for
slurry design, deployment, and monitoring are provided, ensuring replicability
across similar mature fields. In conclusion, expanding cement slurries
represent a reliable and cost-effective method for mitigating water-related
production issues, enhancing wellbore integrity, and improving economic
recovery factors in late-stage reservoirs. This technology offers a scalable
approach for mature field management, with broad implications for maximizing
hydrocarbon recovery and sustaining production efficiency in aging oil fields
worldwide.
Keywords: Enhanced oil recovery; late-stage
development; behind-the-casing flows; water cut; remedial cementing; expanding
cement slurry; well cementing; water inflow isolation; oil fields of
Azerbaijan; improved oil recovery factor (ORF).
*e-mail: fariz.ehmed@socar.az
Date submitted:
22.10.2025 Date accepted:
10.12.2025 |
|
J. M. Eyvazov,
T. A. Aslanov
«Socar Upstream Management International LLC |
Hydraulic fracturing is an engineering process in which specially
formulated fluid and proppant agent are injected into the rock formation at
high pressure to create new fractures or enlarge existing ones. These fractures
significantly improve the flow pathways within the reservoir, enabling
hydrocarbons to move more easily toward the wellbore and eventually to surface
facilities. As one of the most widely used reservoir stimulation methods,
hydraulic fracturing plays a crucial role in increasing production,
particularly in formations with low permeability. The injected proppant agent
prevents fracture closure by remaining within the fractures, thereby ensuring
sustained conductivity over time. The fracturing fluid typically contains a
range of chemical additives, each designed to enhance specific properties such
as viscosity, suspension capacity, friction reduction, and compatibility with
the formation. These additives may include friction reducers, gelling agents,
corrosion inhibitors, biocides, and other specialized components. Proper fluid
formulation directly influences the effectiveness of the operation,
environmental considerations, and the overall safety of the procedure.
Hydraulic fracturing is essential for the development of unconventional reservoirs,
including shale gas, tight gas, and low-permeability oil formations. A
comprehensive understanding of the reservoir’s mechanical properties, porosity,
natural fractures, and the chemical characteristics of formation fluids is
necessary for designing an optimal fracturing operation. Important design
parameters include fracture length, fracture width, fracture conductivity,
fracture geometry, proppant size and concentration, pump rate, and surface
pressure control.
Keywords: hydraulic fracturing; proppant;
fracture conductivity; fracture length; fracture width.
*e-mail: jabrayil.eyvazov88@gmail.com
Date submitted: 24.11.2025
Date accepted: 18.12.2025 |
|
K. F. Aliyev
Azerbaijan State
Oil and Industry University, Baku, Azerbaijan |
Liquid loading remains one of the most critical challenges in the
operation of gas and gas-condensate wells, where the declining reservoir
pressure and reduced gas velocity lead to the accumulation of condensate and
water in the wellbore. This phenomenon increases backpressure, reduces gas
deliverability, and often results in unstable slugging flow. The process is
further complicated by retrograde condensation, where heavy hydrocarbons
condense within the tubing even above the dewpoint pressure, altering the flow
regime and accelerating instability. Traditional empirical models provide
valuable theoretical understanding but are limited by their static assumptions
and inability to capture transient, time-dependent effects observed in field
operations. This study develops an intelligent, data-driven framework that
integrates Artificial Neural Networks and Gated Recurrent Unit architectures
with an automated choke-control system to enable real-time prediction and
control of liquid loading. The Artificial Neural Network model demonstrated an
80% classification accuracy in distinguishing loaded and unloaded well
conditions based on wellhead (bottomhole) pressure, gas rate, and tubing
diameter. The Gated Recurrent Unit based forecasting model achieved a mean
absolute percentage error of 3.98%, effectively capturing daily production
fluctuations and early signs of instability. Integration of both models within
an adaptive control system allows dynamic regulation of wellhead and bottomhole
pressures through automated choke adjustments, maintaining stable flow regimes
and preventing condensate buildup. The hybrid system thus establishes a novel,
self-regulating approach for optimizing gas-condensate production. This
research highlights the potential of combining machine learning and real-time
automation to enhance flow assurance, extend well productivity, and advance the
digital transformation of reservoir management.
Keywords: gas-condensate well; retrograde
condensation; liquid loading; artificial neural network; automated
choke-control system.
e-mail: kananaliyev.kn@gmail.com
Date submitted: 20.11.2025
Date accepted: 23.12.2025 |
Scientific Petroleum 2025, 2
