High-pressure Reservoir Research Articles

Causes of Multi-Mechanism Abnormal Formation Pressure in Offshore Oil and Gas Wells

This study thoroughly investigates the complex origins of abnormal formation pressure in offshore oil and gas wells, taking the Rio del Rey Basin in Cameroon as a case study. Renowned for its abundant oil and gas resources, the area faces unique challenges in predicting overpressure due to its high-temperature and high-pressure reservoir characteristics. By quantitatively analyzing the main mechanisms such as undercompaction, high-temperature fluid expansion, and mud diapirism, the study addresses the complexities of overpressure prediction. This paper introduces an innovative analytical framework that combines hierarchical clustering algorithms with the LightGBM model. Further refined by the application of Bayesian optimization, the model intelligently adjusts hyperparameters to enhance predictive accuracy. Utilizing well logging data and applying machine learning techniques, the paper classifies and identifies different mechanisms causing abnormal pressures, achieving a model prediction accuracy of 0.942. The research findings highlight the predominant role of the undercompaction mechanism, accounting for approximately 70% of the abnormal high-pressure events in the study area. Fluid expansion and shale diapirism contribute smaller but significant proportions of 10% and 20%, respectively. These quantitative insights into the pressure mechanisms are vital for optimizing drilling operations and reducing risks in oil and gas exploration. The study’s hybrid approach, integrating geophysical analysis with advanced computational techniques, sets a precedent for future research. It provides new avenues for applying machine learning to understand complex geological phenomena in similar geological environments and makes a significant contribution to the strategic planning of hydrocarbon exploration and production activities.

Technology Focus: EOR Operations (November 2024)

International agreements and national policies on environmental sustainability are changing the outlook for enhanced oil recovery (EOR) globally. These changes are highlighted by both monetary and intellectual commitments by oil companies around the world. Saudi Aramco has pledged $1.5 billion toward sustainable technology. In practice, members of Aramco’s EXPEC Advanced Research Center have collaborated with King Fahd University of Petroleum and Minerals to develop sustainable surfactants for use in high-temperature, high-pressure, and high-salinity carbonate reservoirs. They used no or only green solvents to produce soluble, stable surfactants with the potential for biodegradability. In Colombia, Ecopetrol is committed to reducing CO2 emission by 25% by 2030. As part of its efforts, it has been optimizing polymer injection in Chichimene, a heavy-oil field. By estimating life cycle greenhouse-gas emissions and energy consumption, it was able to show that polymer injection and its associated carbon intensity reduction could prevent the emission of 3,200 tons CO2 equivalent. To comply with the UK’s North Sea Transition Deal, which mandates a 50% reduction in offshore oil and gas emissions by 2030, Ithaca Energy and Energy Research Norway is using life-cycle assessment to guide more efficient heavy-oil recovery. By using low-dose polymer injection, instead of alternatives such as thermal EOR, it was able to increase exergy while also reducing CO2 emissions by 35%. In these studies, we already see the effect of the energy transition as companies turn away from traditionally effective but environmentally burdensome EOR methods such as steam injection and new polymers that show equal, if not greater, effectiveness with a reduced environmental cost. As we move forward with further regulation and innovation, it will be interesting to see how emerging technological developments in polymers, nanofluids, and even artificial intelligence can help producers meet both the economic and environmental criteria to maintain profitable fields. Recommended additional reading at OnePetro: www.onepetro.org. SPE 218653 Coinjection EOR Technology Increases Recovery and Reduces Greenhouse-Gas Emissions by G. Wasylchuk, GERI SPE 218690 Steam Generation Using Renewables Energy—An Integrated Approach for Enhanced Oil Recovery Applications by Mustafa Al Ajmi, Petroleum Development Oman, et al. SPE 218962 Reaching a Million Barrels in an Abu Dhabi Field by Focusing on Operations Efficiency by Masud J. Akhtar, Abu Dhabi National Oil Company, et al.

Phase Behavior and Rational Development Mode of a Fractured Gas Condensate Reservoir with High Pressure and Temperature: A Case Study of the Bozi 3 Block

The Bozi 3 reservoir is an ultra-deep condensate reservoir (−7800 m) with a high temperature (138.24 °C) and high pressure (104.78 MPa), leading to complex phase behaviors. Few PVT studies could be referred in the literature to meet such high temperature and pressure conditions. Furthermore, it is questionable regarding the applicability of existing condensate production techniques to such a high temperature and pressure reservoir. This study first characterized the phase behavior via PVT experiments and EOS tuning. The operating conditions were then optimized through reservoir numerical simulation. Results showed that: (1) the critical condensate temperature and pressure of Bozi 3 condensate gas were 326.24 °C and 43.83 MPa, respectively; (2) four gases (methane, recycled dry gas, carbon dioxide, and nitrogen) were analyzed, and methane was identified as the optimal injection gas; (3) gas injection started when the production began to fall and achieved higher recovery than gas injection started when the pressure fell below the dew-point pressure; (4) simultaneous injection of methane at both the upper and lower parts of the reservoir can effectively produce condensate oil over the entire block. This scheme achieved 8690.43 m3 more oil production and 2.75% higher recovery factor in comparison with depletion production.

Направления совершенствования сероочистки, осушки и переработки природного газа

The results of the work of the staff of the Department of “Chemical Technology of Oil and Gas Refining” of Astrakhan State Technical University in the field of separation of three-phase reservoir mixture, increasing the efficiency of desulfurization, improving the process of drying gas and the production of continuous hydrocarbons – raw materials for petrochemistry. The influence of the quality of raw materials entering processing on the formation of deposits in technological equipment has been studied. Reconstruction of the inlet and three-phase separators of high-pressure reservoir mixture separation plants by installing a vibration damper and a depulsor on the reservoir mixture supply line to the installation, as well as reconstruction of the input of raw materials into the separator of the installation. The use of the KPG-200 defoamer and the KPG-200 AV antifoamer made it possible to reduce the consumption rate of defoaming reagents several times in gas purification plants from acidic components. The influence of various impurities on the foaming of working amine solutions (mechanical impurities, coal dust, products of thermal destruction of amine, thermostable salts, corrosion inhibitors) has been determined. It was revealed that the products of thermal degradation of amine have the greatest effect at concentrations above 3% by weight. A method for reducing the content of mechanical impurities in a solution of diethanolamine in a constant magnetic field has been developed and introduced into an industrial desulfurization plant. The filtration efficiency increases 2.6 times, the foam height is halved, and the foam stability is quadrupled. At the same time, the activity of the defoamer increases by 1.7 times. The mathematical dependence of the height of the protective layer of aluminum oxide in an adsorber with zeolite on impurities of diethanolamine has been experimentally found. The effectiveness of the developed improved distribution ring device is shown, the use of which makes it possible to practically eliminate dead zones in the zeolite layer and thereby increase the efficiency of the adsorption process and increase the inter-regeneration period on the drying unit. Studies of the catalytic pyrolysis of the butane fraction using CVM-type pentasils modified with the introduction of chromium can reduce the process temperature compared with the thermal decomposition of raw materials by more than one hundred degrees 100 °C.

LARGE-SCALE LANDSLIDES DUE TO SALINE WATER PLUME INTRUSION - AN EXAMPLE OF THE OKIMI LANDSLIDE IN NIIGATA PREFECTURE, JAPAN

Large-scale landslides with volumes ranging from tens to hundreds of millions of m3 are scattered throughout Niigata Prefecture, Japan. There is no accepted theory, although many researchers have argued about the mechanism of these landslides. Highly concentrated Na-Cl type groundwater (hereafter called "saline water") has often been found in large-scale landslides in Niigata Prefecture. In addition, the observation wells where saline water occurs are sometimes flowing wells. We also pay special attention to the distribution of landslide-prone areas and oil and gas fields in Niigata Prefecture, which generally overlap, and saline water from landslides is originally fossil seawater such as oil-brine based on geochemical characteristics. On the other hand, anomalous high-pressure reservoirs at depths of more than 1,000 m in oil and gas fields have been known since the 1960s and are possible saline water sources. We believe saline water's behavior is key to better understanding the mechanism of large-scale landslides. The Okimi landslide, this research area, is located in the Kamiya area, Joetsu City, western part of Niigata Prefecture, Japan. The aspect of the active body is about 500 m wide and 1,500 m long, with an area of about 70 ha. The bedrock geology is mainly Neogene unconsolidated mudstone. According to previous studies, saline water has been detected in observation wells at the head of this landslide. Since the geological formation containing saline water has a considerably low resistivity value (≤ 2.0 Ωm), the CSMT method is best suited for electromagnetic exploration to visualize the resistivity up to 1,000 m depth. The survey results confirm the existence of a saline water plume rising from a "saline water chamber" located 100 to 300 m below the western side of this landslide to the bottom of this landslide (at a depth of about 30 m). The presence of the saline water plume suggests that the upwelling of saline water from the anomalous high-pressure reservoir (saline water chamber) is closely related to several large-scale landslides.

Algorithm for constructing unmeasured logging curves (pseudo-logging) in wells of developed fields

In many cases, the diagrams of some logs in an old well of producing fields are not recorded for some reason or another. Currently, the importance of reassessing the efficiency of such fields is obvious, while the absence of some log curves causes great difficulties. In particular very few studies with acoustic logging (AL) have been carried out in old wells. On the other hand, in 1960-80, among the studies carried out in wells, preference was given to various types of electrical logging (EL), neutron-gamma logging (NGL), and gamma ray logging (GRL). To overcome such difficulties, it is necessary to create diagrams of unmeasured well logs or pseudo-logs. Nowadays, there are methods for constructing pseudolog curves. For example, the method of statistical analysis is widely used. However, in most cases, their implementation is very complex and requires a lot of work. We have developed a new method to construct pseudo-log curves. At first, the propagation velocity of elastic waves in rocks is studied based on seismic survey (SS) and AL data, which are performed presently on the investigation field. Based on this information, objects of interest to the oil industry are selected, their geometric dimensions are determined, the contour of oil and gas saturation is assessed, areas with abnormally high reservoir pressure are studied, the process of accumulation deposition is re-examined, and the preparation of an optimal well network diagram for the effective exploitation of the field is determined. Further, based on the long-ago measured curves of electrical loggings and neutron-gamma logging, we obtain the pseudo-log AL curve in old boreholes and the data SS. The proposed method was tested in 48 wells in the Bahar field (Azerbaijan). The method has shown high efficiency, its reliability is confirmed by independent data. The results of the method help in solving several geological problems: monitoring changes in petrophysical quantities of rocks between wells during development; study of well formations located below the design depth; recalculation of hydrocarbon reserves; determination of the location for drilling new wells, etc

A Comprehensive Approach to Modeling Air Injection-Based Enhanced Oil Recovery Processes

Summary Modeling of air-injection-based processes for enhanced oil recovery (EOR) is a challenging task, mostly due to the complexity of the chemical reactions taking place. Also, the applicability of currently available kinetic models is limited to the reservoir systems they were originally developed for. The objective of this study is to derive a general chemical reaction framework that could be used to develop a kinetic model for a variety of crude oils (i.e., light or heavy oils). The work is based on the modeling of high-pressure ramped temperature oxidation (HPRTO) experiments, and combustion tube (CT) tests, performed on two different oil systems: a volatile oil that is near critical at reservoir conditions (44 °API), and a bitumen sample (10 °API). The HPRTO test is a kinetic experiment that intends to mimic the flow conditions within the reservoir and allows the determination of kinetic parameters of the different reactions. On the other hand, the CT test is meant to provide quantitative information on the combustion performance that can be expected in the field. Therefore, a kinetic model was derived for each of the cases based on the history match of an HPRTO experiment. The resulting model was validated by history matching a CT test for each of the oils. An important feature of these experiments is that they were performed at representative reservoir pressure conditions. The modeling approach chosen is an extension of the methodology originally proposed by Belgrave et al. in 1993, which is arguably the most comprehensive kinetic model available in the air injection literature. However, their model was developed from experiments performed on Athabasca bitumen, and it fails to represent the high-pressure air injection process as it occurs in light oil reservoirs, which are typically encountered at higher pressure conditions. For example, Belgrave’s model is based on the deposition and combustion of semisolid residue commonly known as “coke,” which is rarely present during the combustion of light oils at high pressure. As in Belgrave’s model, this study also describes the original composition of the oil in terms of maltenes and asphaltenes. The main difference lies in the presence and importance of oxygen-induced cracking reactions, as well as the combustion of a liquid-vapor flammable hydrocarbon mixture that is generated by cracking and oxidation reactions, which take place in the gas phase. Also, a unique feature of these simulations is that, apart from history-matching traditional variables such as thermocouple temperatures, fluid recovery, and produced gas composition, they also capture changes in the physical properties of the produced oil, such as viscosity and density, as well as the amount of the residual phases in the post-test core. This enhancement to Belgrave’s reactions allows modeling the air injection process in cases where coke is not the main source of fuel, such as in high-pressure light oil reservoirs. This work changes a paradigm deeply rooted in the original in-situ combustion (ISC) theory, by deriving a general chemical reaction framework that is used to develop a kinetic model for two crude oils, which are at opposite ends of the density spectrum. This allows the consolidation of a new and comprehensive general theory for the description of the ISC process as applied to oil reservoirs. Moreover, as the pseudocomponents representing the fuel are not present in the original oil, the method is not limited to a fluid characterization in terms of maltenes and asphaltenes but could potentially be applied along with any type of characterization of the original oil.

Sustainable Energy Solutions: Utilising UGS for Hydrogen Production by Electrolysis

Increasing the share of renewable energy sources (RESs) in the energy mix of countries is one of the main objectives of the energy transition in national economies, which must be established on circular economy principles. In the natural gas storage in geological structures (UGSs), natural gas is stored in a gas reservoir at high reservoir pressure. During a withdrawal cycle, the energy of the stored pressurised gas is irreversibly lost at the reduction station chokes. At the same time, there is a huge amount of produced reservoir water, which is waste and requires energy for underground disposal. The manuscript explores harnessing the exergy of the conventional UGS reduction process to generate electricity and produce hydrogen via electrolysis using reservoir-produced water. Such a model, which utilises sustainable energy sources within a circular economy framework, is the optimal approach to achieve a clean energy transition. Using an innovative integrated mathematical model based on real UGS production data, the study evaluated the application of a turboexpander (TE) for electricity generation and hydrogen production during a single gas withdrawal cycle. The simulation results showed potential to produce 70 tonnes of hydrogen per UGS withdrawal cycle utilising 700 m3 of produced field water. The analysis showed that hydrogen production was sensitive to gas flow changes through the pressure reduction station, underscoring the need for process optimisation to maximise hydrogen production. Furthermore, the paper considered the categorisation of this hydrogen as “green” as it was produced from the energy of pressurised gas, a carbon-free process.

Multistep-Ahead Prediction of Logging-While-Drilling Resistivity Curves Based on Seismic-Guided Seq2Seq-Long Short-Term Memory

Summary High-temperature and high-pressure reservoirs in complex geological conditions present primary targets and significant challenges in deepsea oil and gas exploration. Limited offshore drilling operations and lack of detailed geological data hinder accurate formation pressure prediction using geoguided and offset imaging, increasing drilling hazards. Logging-while-drilling (LWD) technology provides timely and accurate subsurface information. Resistivity closely correlates with formation pressure and lithology, aiding pressure prediction. Therefore, in this study, we developed an ahead prediction workflow for LWD curves using the resistivity curve (RD) as an example. A seismic-guided sequence-to-sequence framework with the long short-term memory model (Seq2Seq-LSTM) is used to predict the RD curve at a constant depth ahead of the drill bit, utilizing the RD curve of drilled sections and seismic attributes. The network structure incorporates a direct-recursive hybrid multistep prediction strategy based on update threshold control (Dir-Rec-Update), aligning with real-time LWD data acquisition for ahead curve prediction. Using real well data cross-prediction, baseline models such as multilayer perceptron (MLP) and extreme gradient boosting (XGBoost) were compared while also investigating the impact of different configurations on the proposed Seq2Seq-LSTM. The results demonstrate that the method outperforms conventional models, with an average performance across multiple wells under a 5-m update threshold: root mean square error (RMSE) of 0.15, correlation coefficient of 0.88, and coefficient of determination of 0.77. The Seq2Seq-LSTM model and Dir-Rec-Update strategy provide accurate LWD curves ahead of the drill bit, enabling advanced drilling decisions and preventing hazards. Advanced technologies such as empirical wavelet transform (EWT) and feature selection enhance the method’s potential for curve ahead-of-time prediction.

Economic and exergy transmission analysis of the gas-liquid type compressed CO2 energy storage system

Exergy transmission characteristic of the compressed CO2 energy storage system is significant to evaluate the system performance while little attention has been paid to this analytical method in the literature. A CO2 energy storage cycle configured with a gas holder as a low-pressure gas reservoir and a liquid tank as a high-pressure gas reservoir is studied comprehensively. The exergy transmission characteristics and the cost uncertain analysis are considered. Results demonstrated that the round trip efficiency and levelized cost of storage are 71.2 % and 0.1286 $/kWh under optimal design parameters, respectively. Keeping the charge/discharge duration ratio close to 1 has a positive effect on optimizing the economic performance of the system. With the general exergy model of the whole system configured for the charge and discharge process, the study uncovers the fluctuations in the pertinent proportional ratios and exergy transfer efficiency in relation to important parameters. Except for the turbomachinery isentropic efficiency, which impacts nearly all efficiencies, the variation of each parameter only governs the modification of the exergy transfer efficiency for a specific term or a pair of terms. Furthermore, the thermal exergy efficiency of the discharge process and intercooler has a maximum value as the cold-side temperature difference of the high-temperature cooler changes to 27 °C.

Simulation and Analysis of Temperature and Pressure Fields in the Wellbore of Self-Injection Well

Aiming at the problem of wellbore waxing in high-temperature, high-pressure and highly-waxed deep gas condensate reservoirs, a wellbore temperature/pressure field prediction model for self-injection wells was established with the site parameters of the Bozi gas condensate field in the Tarim Basin of China using the OLGA software. With the help of the parameters of example wells on site in the Bozi, wellbore temperature and pressure in the process of gas extraction from 10 self-injector wells were predicted, and the following findings were obtained: the temperature decreases gradually in the process of condensate gas well lifting, and the slopes of the temperature profile shown an overall The overall slope of the temperature profile shown a trend of gradually becoming larger, indicating that the temperature drop was increasing, and the single wells in the block reflect similar wellbore temperature profile characteristics. During the lifting process, the pressure gradually decreases, and the slope of the pressure profile does not change significantly, indicating that the pressure drop along the way was relatively constant, and the single wells in the block reflect similar wellbore pressure field distribution characteristics. Combining the temperature gradient and pressure gradient interpretation data of different wells and time interfering test wells in Bozi, and using them as the basis for temperature and pressure profile regression, the above 10 condensate wells in Bozi block were classified according to different temperatures and pressures, and the temperature and pressure profiles were regressed and fitted to fit the actual working conditions, which lays a data basis for the analysis of wax formation in the example wells in Bozi.

An evaluation of the permeability obtained from the gas-hydrodynamic studies of the wells of the Turonian deposit at the Yuzhno-Russkoye field

This article is devoted to a qualitative and quantitative evaluation of the permeability values obtained during gas-hydrodynamic well tests with observation well testing in the Turonian deposits of the Yuzhno-Russkoye field. As is well known, Turonian deposits of Western Siberia belong to hard-to-recover reserves. The Turonian reservoir is characterized by low permeability, abnormally high initial reservoir pressure and abnormally low temperature. The obtained data can be used to clarify the geological structure of the field during further development of the deposit. When conducting gas-hydrodynamic studies in the production well, a depth gauge was lowered into the observation well together with hydrostatic listening. The response obtained in the well that was reacting well to stop the well that was perturbing indicates the hydrodynamic connection between the wells. The formula for determining the survey radius was used to calculate the average effective permeability between the wells. When the permeabilities determined according to gas-hydrodynamic studies and observation well testing were compared, it was noted that the data converged. Based on the results, it was decided to carry out gas-hydrodynamic studies together with observation well testing in the future.

Monitoring geomechanical pumped storage in horizontal fluid-filled lenses with surface tiltmeters

Geomechanical Pumped Storage is a long duration energy storage technology that assists with integrating variable renewable energy sources into the electricity grid. The concept involves cycling fluid in artificial subsurface lenses. These lenses act as high-pressure reservoirs, storing and releasing pressurised fluid to drive a turbine and generate power. Similar in nature to traditional pumped storage hydropower, but lower cost, modular, and without the specific topography requirements. This work describes the surface monitoring and analysis from several lenses manufactured in the Eagle Ford Shale at Quidnet Energy’s Castilleja pilot storage site in Texas. Up to 12 high-precision tiltmeters were used to verify dip and orientation of the lens as well as provide a predictive map of the lens geometry and symmetry or asymmetry of the lens growth. The surface tiltmeters used as a diagnostic tool for lens creation have been proven to be useful. It provides operators with confidence and feedback on fundamental lens behaviour and response. These improvements will help scale the technology to commercially viable modular energy storage systems.

Pore Pressure Prediction for High-Pressure Tight Sandstone in the Huizhou Sag, Pearl River Mouth Basin, China: A Machine Learning-Based Approach

A growing number of large data sets have created challenges for the oil and gas industry in predicting reservoir parameters and assessing well productivity through efficient and cost-effective techniques. The design of drilling plans for a high-pressure tight-sand reservoir requires accurate estimations of pore pressure (Pp) and reservoir parameters. The objective of this study is to predict and compare the Pp of Huizhou Sag, Pearl River Mouth Basin, China, using conventional techniques and machine learning (ML) algorithms. We investigated the characteristics of low-permeability reservoirs by observing well-logging data sets and cores and examining thin sections under a microscope. In the reservoir zone, the average hydrocarbon saturation is 55%, and the average effective porosity is 11%. The tight sandstone reservoirs consist of fine- to extremely fine-grained argillaceous feldspathic sandstone. The mean absolute error for reservoir property prediction is 1.3%, 2.2%, and 4.8%, respectively, for effective porosity, shale volume, and water saturation. Moreover, the ML algorithm was employed to cross-check the validity of the prediction of Pp. Combining conventional and ML techniques with the core data demonstrates a correlation coefficient (R2) of 0.9587, indicating that ML techniques are the most effective in testing well data. This study shows that ML can effectively predict Pp at subsequent depths in adjacent geologically similar locations. Compared to conventional methods, a substantial data set and ML algorithms improve the precision of Pp predictions.

Estimating the Influencing Factors of Gas–Water Relative Permeability in Condensate Gas Reservoirs under High-Temperature and High-Pressure Conditions

The gas–water relative permeability curve plays a crucial role in reservoir simulation and development for condensate gas reservoirs. This paper conducted a series of high-temperature and high-pressure analysis experiments on real gas cores from Wells A and B in Block L of the Yinggehai Basin to investigate the effects of temperature, pressure, and different types of gas media on gas–water seepage. The gas–water relative permeability was simulated in this experiment through variations in temperature, pressure, and gas composition. Temperature has a significant impact on both gas and water relative permeability, particularly on gas relative permeability. As temperature increases, gas relative permeability shows a substantial increase, while water relative permeability remains relatively unchanged. Under the same effective stress, increasing pressure causes downward shifts in both the gas and water relative permeability curves; however, there is a more pronounced decrease in gas relative permeability. Gas composition has minimal influence on the gas–water relative permeability except at higher water saturation where differences become apparent. When water saturation ranges from 80% to 50%, there is no significant variation observed in the measured relative permeability of different displacement gases. However, as water saturation exceeds 80%, distinctions gradually emerge. The relative permeability of nitrogen is approximately 92% lower than that of mixed gas when the bound water saturation reaches 80%. This investigation provides valuable insights into the characteristics of gas–water relative permeability in high-temperature and high-pressure condensate reservoirs within Yinggehai Basin, thereby offering significant contributions to development strategies for similar reservoirs.

Diagenetic Impact on High-Pressure High-Temperature Reservoirs in Deep-Water Submarine Fan Sandstone of Qiongdongnan Basin, South China Sea

The diagenetic evolution of sandstone is very complicated under the conditions of high temperatures and pressures in deep-water, deep-buried regimes, which have great influence on reservoir quality. This study investigates the typical reservoir target of Neogene deep-water, submarine-fan sandstones under high-temperature, high-pressure regimes in the Qiongdongnan Basin, South China Sea. Utilizing a thin section, scanning electron microscope (SEM), mineral geochemistry combined with burial history evolution, complex diagenetic events, and main controlling factors of the sandstone in the Neogene Meishan Formation were determined. The results show that the evolution of sandstone reservoirs is initially controlled by depositional framework compositions and subsequently modified by eogenetic and mesogenetic alterations during progressive burial. Eogenetic alterations mainly include the following: (1) mechanical compaction; (2) dissolution of feldspar; (3) low-Fe calcite cementation. Mesogenetic events were identified as the following: (1) dissolution of feldspar; (2) ferroan calcite and ankerite formation; (3) precipitation of quartz and clay mineral. Mechanical compaction is greatly influenced by the original depositional framework composition, and sandstone samples enriched in high contents of detrital clay matrix always experienced extensive mechanical compaction. Different phases of carbonate cement during different diagenetic regimes lead to continuous destruction on reservoir porosity. The dissolution of unstable feldspar minerals during eogenetic and mesogenetic environments leads to the development of secondary porosities and would enhance the quality of the reservoir. Overpressure formation is pervasively developed owing to early disequilibrium compaction and subsequent natural gas charging. Only well-sorted sandstones with low contents of detrital clay matrix could resist early mechanical compaction, lead to ample residual original porosities, and then undergo extensive mineral dissolution to generate sufficient secondary porosities. Subsequently, these porosities would be effectively protected by overpressure formation. Poor-sorted sandstones with high contents of detrital clay matrix would experience strong mechanical compaction and extensive destruction of original porosities. Thus, these sandstones are difficult to have significant dissolution and are unable to be effectively protected by overpressure formation. Therefore, the interplay between the original framework composition and the corresponding diagenetic pathways coupled with overpressure formation would result in strong reservoir heterogeneity for the deep-buried sandstones during progressive burial.

Influence of geotemperature conditions on the oil and gas potential of the South Caspian depression (the case of the Lower Kura depression and Baku archipelago)


 
 
 In the article, the oil and gas potential of the deep-lying sediments of the Lower Received in revised form 13.08.2023; Kura depression and the Baku archipelago, which are geostructural elements of the South Accepted 13.11.2023 Caspian depression, are investigated according to the geotemperature conditions. The main aim of the research is identifying the oil-gas «windows» in the 22-24 km thick sedimentary rock complex of the South Caspian depression based on the geothermal factor. Using temperature values measured at different depth sections in different structures of the Lower Kura depression and Baku archipelago, temperature distribution maps of the area and a graph of changing temperature by depth were constructed. According to the geothermal maps constructed for the Lower Kura depression, a relatively high temperature value is observed in the north-west part of the area. This anomalous value is related to the location of active, periodically erupting mud volcanoes, which play an important role in temperature distribution, as well as local uplifts, which are more complicated by tectonic landslides and upthrusts. At great depths (5,500-6,500 m) within the research region, almost everywhere, anomalously high pore and reservoir pressures are observed, which create the conditions for the manifestation of tectonic-physical processes and the generation of great energy affecting the oil and gas potential of the area. In all the geotemperature maps constructed for different depth intervals in the Baku archipelago, high temperature values are observed in the north zone where the Sangachal-deniz-Duvanni-deniz-Khara-Zira island and Alat-deniz structures are located. This is due to the complication of uplifts by active mud volcanoes, which play an important role in the formation of local heat sources. The Khara-Zira island mud volcano, the largest in the Baku archipelago, is also located here. Based on the analysis of the temperature values in the research areas, a decrease in the temperature values is observed due to increase in the thickness and the clay content of the sedimentary layer in the direction from the Lower Kura depression to the South Caspian basin. The temperature is 990C at 5,000 m in the Lower Kura depression, 900C in the Baku archipelago. So, a decrease in temperature is characteristics for all depths. The analysis of the compiled graphs shows that the top of the main zone of oil formation in the Lower Kura depression starts at a depth of 2,000-2,500 m, and the lower limit is located at a depth of about 9,000 m (1500 C). The top of the main zone of oil formation in the Baku archipelago starts at a depth of 3,000 m, and the lower limit is located at a depth of 9,000-11,000 m. So, it shows that as the oil and gas formation sources the potential oil source rocks in the Lower Kura depression and the Baku archipelago at the depth range from 2,000-2,500 m to 8,000-11,000 m can produce industrially important oil and gas.
 
 

Multisource working condition recognition via nonlinear kernel learning and p-Laplacian manifold learning

Effectively utilizing information from multiple sources and fewer labeled operating condition samples from a sucker-rod pumping system for oil production can improve the recognition effects and engineering practicability. Nevertheless, this is a challenging energy environment scientific application research subject, and therefore, this study proposes an operating state recognition scheme that relies on multisource nonlinear kernel learning and p-Laplacian high-order manifold regularization logistic regress. Specifically, three measured features are selected and extracted, i.e., wellhead temperature signal, electrical power signal, and ground dynamometer cards, based on mechanism analysis, expert experience, and prior knowledge. Finally, we establish the operating condition recognition model to recognize by the multisource p-Laplacian regularization kernel logistic regress algorithm. The experimental data are derived from 60 wells of a common high-pressure and low-permeability thin oil reservoir block of an oil field in China. The corresponding trials highlight that our scheme outperforms traditional recognition methods by exploiting single-source and multiple-feature data. In the context of fewer labeled samples, the proposed method has a greater recognition effect, engineering practicability, and better model robustness than the existing schemes based on other high-order manifold learning, verifying our method's effectiveness.

A transient production prediction method for tight condensate gas wells with multiphase flow

Considering the phase behaviors in condensate gas reservoirs and the oil-gas two-phase linear flow and boundary-dominated flow in the reservoir, a method for predicting the relationship between oil saturation and pressure in the full-path of tight condensate gas well is proposed, and a model for predicting the transient production from tight condensate gas wells with multiphase flow is established. The research indicates that the relationship curve between condensate oil saturation and pressure is crucial for calculating the pseudo-pressure. In the early stage of production or in areas far from the wellbore with high reservoir pressure, the condensate oil saturation can be calculated using early-stage production dynamic data through material balance models. In the late stage of production or in areas close to the wellbore with low reservoir pressure, the condensate oil saturation can be calculated using the data of constant composition expansion test. In the middle stages of production or when reservoir pressure is at an intermediate level, the data obtained from the previous two stages can be interpolated to form a complete full-path relationship curve between oil saturation and pressure. Through simulation and field application, the new method is verified to be reliable and practical. It can be applied for prediction of middle-stage and late-stage production of tight condensate gas wells and assessment of single-well recoverable reserves.

Study on the applicability of compressed carbon dioxide energy storage in aquifers under different daily and weekly cycles

To study the operational characteristics of the subsurface part of the compressed CO2 energy storage in aquifers under different energy storage cycles, two daily and two weekly cycles for energy storage are designed, respectively. The whole process consisting of a two-year initial filling period and a one-year cyclic injection-production period is simulated. The results show that a total of 1.5552 million tons of CO2 can be stored in the initial filling period under the design condition. Sufficient initial fill can provide continuous pressure support for the subsequent injection and production cycles, and the output pressure and temperature are appropriate for electricity generation for one year in both the two daily and the two weekly cycles. The power generation process of the system in the two daily cycles and weekly cycles has a high production flow rate, and the average mass flow loss of daily and weekly cycles is about 0.3 % and 1 %, respectively. Due to the replenishment effect of geothermal energy, the average energy efficiencies in the whole process in the low- and high-pressure reservoirs under the two cycles are both higher than 100 %. These findings indicate that achieving good performance is possible for various long-duration energy storages.