Development Of Carbonate Reservoirs Research Articles

The Main Controlling Factors of the Cambrian Ultra-Deep Dolomite Reservoir in the Tarim Basin

The genesis of deep-to-ultra-deep dolomite reservoirs in the Tarim Basin is crucial for exploration and development. The Cambrian subsalt dolomite reservoirs in the Tarim Basin are widely distributed, marking significant prospects for ultra-deep reservoir exploration. Based on big data methodologies, this study collects and analyzes porosity and permeability data of carbonate reservoirs in the western Tarim Basin, specifically targeting the Cambrian deep-oil and gas-reservoir research. Through an examination of the sedimentary evolution and distribution of carbonate–evaporite sequences, and considering sedimentary facies, stratigraphic sediment thickness, fault zone distribution, and source-reservoir assemblages as primary reference factors, the study explores the macro-distribution patterns of porosity and permeability, categorizing three favorable reservoir zones. The controlling factors for the development of Cambrian carbonate reservoirs on the western part of the Tarim Basin are analyzed from the perspectives of sedimentary and diagenetic periods. Factors such as tectonic activity, depositional environment, microbial activity, and pressure dissolution are analyzed to understand the main causes of differences in porosity and permeability distribution. Comprehensive analysis reveals that the porosity and permeability of the Series2 carbonate reservoirs are notably high, with extensive distribution areas, particularly in the Bachu–Tazhong and Keping regions. The geological pattern of “Three Paleo-uplifts and Two Depressions” facilitated the formation of inner-ramp and intra-platform shoals, creating conducive conditions for the emergence of high-porosity reservoirs. The characteristics of reservoir development are predominantly influenced by diagenetic and tectonic activities. The Miaolingian is chiefly affected by diagenesis, featuring high permeability but lower porosity and smaller distribution range; dolomitization, dissolution, and filling processes under a dry and hot paleoclimate significantly contribute to the formation and preservation of reservoir spaces. In the Furongian, the Keping and Bachu areas display elevated porosity and permeability levels, along with substantial sedimentary thickness. The conservation and development of porosity within thick dolomite sequences are mainly governed by high-energy-particulate shallow-shoal sedimentary facies and various dissolution actions during diagenesis, potentially indicating larger reserves.

Classification of rock types of porous limestone reservoirs: case study of the A oilfield

Rock types with similar lithological components and pore structures form the basic units of porous limestone reservoirs; this influences the reservoir evaluation efficiency and water injection development. As the main oil and gas pay zone in central Iraq, the Cretaceous Khasib Formation reservoirs are influenced by deposition, dissolution, and cementation. There is strong vertical heterogeneity in the most important zone of the Kh2 layer, with diverse rock types and complex pore structures. Based on core observation and casting thin-section identification, the Kh2 layer in the study area was divided into eight lithofacies types as argillaceous bioclastic wackestone, planktic foraminiferium wackestone, lamellar bioclastic wackestone, intraclastic–bioclastic packstone, patchy green algae packstone, green algae and pelletoid packstone, benthic foraminiferium–bioclastic packstone, and intraclastic grainstone. Along with the reservoir void space types of the lithofacies, capillary pressure curves are used to quantitatively analyze the throat and pore features of the different lithofacies. From the porosity–permeability cross-plot characteristics and distribution of pore types, 14 petrophysical facies are obtained. Finally, based on the differences between the lithofacies and petrophysical facies, the Kh2 member is divided into 13 rock types with different geological origins and petrophysical characteristics. Among these, the rock type RT1-8-14 has the best and rock type RT1-1-1 has the worst physical properties among the reservoir rock types. This study provides an optimization method for carbonate reservoir evaluation and is expected to be beneficial for efficient development of similar carbonate reservoirs.

Experimental study and prediction method of solid destabilization and production in deep carbonate reservoir during mining

Wellbore instability is one of the significant challenges in the drilling engineering and during the development of carbonate reservoirs, especially with open-hole completion. The problems of wellbore instability such as downhole collapse and silt deposit in the fractured carbonate reservoir of Tarim Basin (Ordovician) are severe. Solid destabilization and production (SDP) was proposed to describe this engineering problem of carbonate reservoirs. To clarify the mechanism and mitigate potential borehole instability problems, we conducted particle size distribution (PSD) analysis, X-ray diffraction (XRD) analysis, triaxial compression tests, and micro-scale sand production tests based on data analysis. We found that the rock fragments and silt in the wellbore came from two sources: one from the wellbore collapse in the upper unplugged layers and the other from the production of sand particles carried by the fluid in the productive layers. Based on the experimental study, a novel method combining a geomechanical model and microscopic sand production model was proposed to predict wellbore instability and analyze its influencing factors. The critical condition and failure zone predicted by the prediction model fit well with the field observations. According to the prediction results, the management and prevention measures of wellbore instability in carbonate reservoirs were proposed. It is suggested to optimize the well track in new drilling wells while upgrading the production system in old wells. This study is of great guiding significance for the optimization of carbonate solid control and it improves the understanding of the sand production problems in carbonate reservoirs.

Differential fault-fluid alterations and reservoir properties in ultra-deep carbonates in the Tarim Basin, NW China

The development of high-quality carbonate hydrocarbon reservoirs in the ultra-deep (7000–10000 m) Lower Paleozoic strata of the Tarim Basin was substantially related to tectonic evolution, strike-slip faults, and diagenetic fluids. Detailed studies of the influences of tectonic evolution and strike-slip faults on the properties of diagenetic fluids and the development mechanisms of ultradeep carbonate reservoirs under the control of both faults and fluids are required to identify high quality reservoirs. In this study, end-member geochemical indicators of meteoric water, hydrothermal fluid, and formation fluid were constructed based on typical diagenetic mineral and geochemical data obtained from representative wells. Meteoric karst associated with strong tectonic uplift was the main diagenetic event along strike-slip faults in the Tahe area. The Shunbei area was generally affected by buried formation water, and locally by weak meteoric water or hydrothermal fluids. The Tazhong, Shunnan, and Gucheng areas were predominantly affected by strong hydrothermal fluids along strike-slip faults associated with strong volcanic activity, while some wells, such as TZ12, reveal the influence of thermochemical sulfate reduction (TSR). Differences in fault fluid types and properties resulted in differential development of ultra-deep carbonate reservoirs among the different areas. In the Tahe area, meteoric water alteration along faults formed karst fracture-cavity reservoirs. In the Shunbei area, fault-cavity carbonate reservoirs were formed by strong strike-slip faults, whereas fluid alteration was weak. Hydrothermal dissolution reservoir in the Tazhong area, hydrothermal silicification reservoir in the Shunnan area, and hydrothermal dolomitization reservoir in the Gucheng area are developed, respectively.

Research on water-out mode and differential perforation in thick carbonate reservoir

The development of anti-rhythmic carbonate reservoirs in the Middle East often encounters challenges such as water hold-up and reverse coning during the water injection process, leading to premature water breakthrough and various water-out issues. The unclear understanding of these phenomena, attributed to strong reservoir heterogeneity, results in a relatively low recovery degree in water injection development. This paper investigates the mechanisms behind water hold-up and reverse coning phenomena, offering detailed solutions. Numerical models of the oil reservoirs were developed, and an extensive study of influencing factors, including reservoir types, Kv/Kh, water injection pressure differential, wettability, and perforation position, was conducted to unveil the underlying mechanisms. Key findings indicate that the water hold-up phenomenon is influenced by capillary force barriers due to wettability and high-perm streaks, while the reverse coning phenomenon depends on the combined forces of gravity, capillary force and downward production differential among which downward production differential is the dominant factor compared to capillary force and gravity. The study also proposes a differential perforation principle tailored to different water-out types to enhance vertical sweep efficiency. The differential perforation principle is as follows: the optimal perforation position is at top layer and the optimal perforation length approximately accounts for 1/4 of the total oil layer thickness for water-out in bottom; the avoidance perforation height in top accounts for 1/6 of the total oil layer thickness and the optimal perforation length approximately accounts for 1/2 of the total oil layer thickness for water-out in top; the avoidance perforation height in top and bottom accounts for 1/5 and 2/5 of the total oil layer thickness respectively for water-out in both top and bottom.

The research on high efficiency water injection development of carbonate rock reservoir in the middle east

More and more attention has been paid to the waterflood development of carbonate reservoir in the Middle East with continuous expansion of the scale of carbonate reservoir development. Strong non-homogeneity of carbonate reservoirs results in serious conflicts between injection and production, causing low degree of water-driven control in the well network, and low degree of vertical mobilization. This article takes the main reservoir of an oil field in the Middle East region as an example, combining geological evaluation, dynamic analysis, and reservoir development strategies to study the effectiveness of water injection development in carbonate reservoirs. It shows that there is a correlation between pore type, oil-water relative permeability, and development method in the development of carbonate reservoirs. For reservoirs with matrix pores and micropores, water injection should be strengthened in the later stage of development; for reservoirs with dissolved pores and coarse pores, the iso-permeability point is relatively high, and the later development should focus on balanced water injection. Three different waterflooding models for formation development are designed to verify the feasibility of fine waterflooding schemes. The main differences are that one set of well patterns is combined injection and production, and three sets of well patterns are layered system waterflooding. The results show that the development effect in layered system waterflooding is the best. The daily production can be increased by about 16%, the cumulative oil production can be increased by about 8%, and the recovery factor can be increased by about 3%. Eventually, the stable oil and water control of carbonate reservoir can be realized.

Joint inversion of crack properties of tight carbonates from electrical conductivity and ultrasonic velocity

Understanding the effects of cracks on the elastic and electrical properties of tight carbonates is crucial for the exploration and development of deep and ultra-deep carbonate reservoirs. In this work, the porosity, electrical conductivity and ultrasonic velocities of two brine-saturated carbonate samples (where the pore space is dominated by cracks) are measured jointly at different effective pressures (5–90 MPa), as well as the velocities with saturating nitrogen at the same pressure conditions. The results show non-linear changes in the measured values, indicating a correlation with the presence of cracks. To analyze the pressure-dependent elastic and electrical properties, an approach combining a multiphase Kachanov model with a multiphase reformulated electrical differential effective medium (REDEM) model is proposed. This approach agrees well with the pressure-dependent experimental results of brine-saturated carbonate samples. The crack aspect ratio spectra are estimated using the experimental porosity as a constraint to improve the accuracy of the inverted crack geometry. The spectra from the elastic (electrical) inversion are input into the multiphase REDEM (Kachanov) model to predict the electrical conductivity (wave velocities). Comparisons with laboratory measurements show the ability of the proposed approach to estimate elastic wave velocities from the electrical conductivity using the inverted crack geometry, and vice versa.

Tight carbonate reservoir evaluation case study based on neural network assisted fracture identification and analytic hierarchy process

Comprehensive evaluation of reservoirs is an important link in gas reservoir exploration and development. The evaluation of tight carbonate reservoirs often focuses on the characteristics of porosity and permeability, ignoring the important factor of fractures, also the quantitative evaluation of reservoirs is relatively few. It is difficult to identify fractures and evaluate the reservoir factors qualitatively and quantitatively. Herein, the sedimentary microfacies and microporosity of the tight carbonate reservoir of the Ma55 submember in the eastern Sulige area are comprehensively studied by casting thin section, rock physical property, and capillary pressure test data. The backpropagation (BP) neural network algorithm is used to identify and predict fractures. Finally, through the analytic hierarchy process, the above reservoir influencing factors are modeled and quantitatively analyzed for reservoir evaluation. The results show that the highest probability of fracture development in the central and northwest areas of the study area can reach 0.92. The accuracy of the BP neural network model in identifying cracks can reach 80%, which is reliable and effective compared with the conventional logging identification method. Reservoirs can be classified into four types according to their quality. The synthetic weights of porosity, permeability and fracture development probability are 0.2, 0.2 and 0.216 respectively, which are the three most important evaluation parameters. This study improves the accuracy of fracture identification and prediction of tight reservoirs in comprehensive reservoir evaluation, which provides guidance and scheme for more detailed exploration and development of tight carbonate reservoirs.

Impact of rock heterogeneity on reactive flow during acid stimulation process

Acid stimulation within carbonate rocks represents a crucial aspect of reactive flow applications in subsurface porous media and has been widely used in carbonate reservoir development attributed to its rapid effectiveness and cost-efficiency. This study is motivated to investigate further the impact of rock heterogeneity on the acid stimulation process. The two-scale continuum model is employed for capturing mass, momentum, and energy transfer during the acid stimulation process. The core-scale model is expanded to consider the specific composition of solid minerals, including reactive minerals such as calcite and dolomite and non-reactive ones like quartz and clay. A heterogeneity generator is developed by coupling with the open-source geostatistical program to produce different heterogeneous parameters using random seeds with varying spatial correlation lengths. Sensitive cases are performed to present an investigation into the influence of mineral composition and matrix heterogeneity on the acid stimulation process. Results show that the typical results of acid stimulation are closely tied to different heterogeneity conditions. The optimum conditions for acid stimulation are sensitive to the concentration of reactive components. The optimum acid injection rate declines as dolomite content increases, while the corresponding acidizing breakthrough volume reduces with higher calcite levels. The presence of mineral layers, especially in horizontal distributions, complicates acid fluid efficiency due to the competitive reaction between calcite and dolomite. Compared to the heterogeneous distribution of minerals, matrix heterogeneity plays a critical role in acid fluid consumption efficiency. Increasing heterogeneity leads to significant reductions in breakthrough volumes, largely governed by the correlation length.

Impact of Burial Dissolution on the Development of Ultra‐deep Fault‐controlled Carbonate Reservoirs: Insights from High‐temperature and High‐pressure Dissolution Kinetic Simulation

AbstractBurial dissolution is a critical diagenetic process influencing ultra‐deep carbonate reservoir development and preservation. Artificial carbonate samples with different internal structures were prepared, and high‐temperature and high‐pressure dissolution kinetic simulations were conducted. The results demonstrate that the intensity of burial dissolution is controlled by temperature and pressure, while tectonic‐fluid activity influences the development pattern of burial dissolution, ultimately determining the direction of its differential modification. Extensive burial dissolution is likely to occur primarily at relatively shallow depths, significantly influencing reservoir formation, preservation, modification, and adjustment. The development of faults facilitates the maintenance of the intensity of burial dissolution. The maximum intensity of burial dissolution occurs at the tips and overlap zones of faults and intersections of multiple faults. The larger the scale of the faults, the more conducive it is to the development of burial dissolution. Burial dissolution fosters the formation of fault networks characterized by enhanced reservoir capacity and permeability. Burial dissolution controlled by episodic tectonic‐fluid activity is a plausible explanation for forming the Tarim Basin's ultra‐deep fault‐controlled “string‐bead‐like” reservoirs.

Molecular dynamics simulation and key performance study of VES self-diverting acid system for deep carbonate reservoirs

Viscoelastic Surfactant (VES) self-diverting acid technology is an ideal approach for enhanced recovery from heterogeneous reservoirs. Most VES self-diverting acid systems currently used in field operations are only suitable for low-temperature reservoirs, and research on self-diverting VES acid systems for deep carbonate rock formations is lacking. Additionally, studies on the molecular dynamics of the self-assembly of VES have mainly focused on cationic surfactants, with insufficient research on the self-assembly of betaines in the oil industry. This study investigated the effects of temperature, surfactant concentration, and metal ion concentration on the self-assembly of erucamide propyl hydroxysulfobetaine (EHSB) based on a self-assembly model through molecular simulation methods. Moreover, the viscosity of the EHSB was predicted under various conditions. The results indicated that the system viscosity was optimal at an EHSB concentration of 4 wt%. The EHSB system requires initiation by metal ions to enhance the viscosity, with Ca2+ having a more pronounced effect than Mg2+. This is attributed to the formation of a unique “octahedral” structure by Ca2+ in solution, which aids in the formation of large micelles. Furthermore, because of the smaller ionic radius of Mg2+ compared with that of Ca2+, Mg2+ is more likely to penetrate micelles and form salt bridges, promoting a tighter arrangement of surfactant molecules. Based on molecular simulation and laboratory experiments, under optimal concentrations of inorganic salts and EHSB, the system’s viscosity remained greater than 150 mPa·s at 140 °C, meeting the requirements for diversion in deep carbonate rock formations. Finally, the acidization capacity and diversion effects of the acidic system were demonstrated using single-core flood and dual-core diversion experiments. The results showed that the acid solution significantly etched the core, and the residual acid reduced the permeability contrast of the core from 3.54 to 2.35, indicating a good acidizing diversion performance. This study utilizes a combination of computer simulations and laboratory experiments to optimize a VES self-diverting acid system. The computer-predicted viscosity corresponds well with the actual measured viscosity, providing new technical insights for evaluating the performance of VES under complex formation conditions that are unattainable through laboratory tests. A self-diverting VES acid system suitable for deep carbonate rock reservoirs at 140 °C was developed, providing technical support for the efficient development of deep carbonate reservoirs.

Study on the Mechanism of Stress Sensitivity Changes in Ultra-Deep Carbonate Reservoirs

Quantitative evaluation of stress sensitivity of ultra-deep carbonate reservoirs has been one of the challenges in exploration and development, and the problem of permeability loss law in ultra-deep carbonates under variable stress conditions has not been solved so far and further research is urgently needed. Through experimental and numerical simulation methods, the stress-sensitive evaluation equations were established based on matrix-type carbonate and fractured carbonate reservoirs, the stress-sensitive changes under different Young’s modulus were discussed, and the degree of permeability loss under different stresses was evaluated. Finally, the dual-media model of ultra-deep carbonate was established, and the practical application was carried out in the Shunbei area of the Tarim Basin. Studies have shown that (1) under the same effective stress, the stress sensitivity of matrix-type and fracture-type carbonate reservoirs is related to the Young’s modulus of the rock skeleton. In matrix-type carbonate reservoirs, rocks with a larger Young’s modulus have smaller rigidity and stronger stress sensitivity. In fracture-type carbonate reservoirs, the stress sensitivity is relatively weak under a smaller Young’s modulus, and relatively strong under a larger Young’s modulus. (2) Measured under the conditions of 87 MPa of peripheral pressure, 50 MPa of flow pressure, and 120 °C, the effective stress of matrix-type carbonate reservoirs has an exponential relationship with the permeability of reservoirs. The degree of stress sensitivity for fracture-type is generally higher than that of matrix-type reservoirs, and the smaller the Young’s modulus, the larger the difference in stress sensitivity. (3) The stress sensitivity of typical ultra-deep carbonates in the Shunbei area of the Tarim Basin is higher by establishing a dual-porosity model based on the initiating pressure gradient, which supports new evidence for the characteristics of ultra-deep carbonates with high-stress sensitivity. In actual production, the impact of stress sensitivity on the reservoir volume calculation and efficient development of ultra-deep carbonate reservoirs requires critical attention.

Meteoric water effect of diagenesis processes in deep carbonate reservoirs

As the world’s main oil and gas resource, the deep carbonate reservoir has great exploration-development potential. However, it is difficult to make development and exploration due to its complex diagenesis processes. During the formation of carbonate reservoirs, the effect of meteoric water forms karst holes for oil and gas reservoirs, but the complex internal mechanism severely restricts the exploration and development of carbonate reservoirs. This paper takes the deep carbonate reservoirs in the Tarim Basin as the research object, studies the diagenesis processes in deep carbonate reservoirs through geological survey, analyzes the effect of meteoric water on porosity and mineral changes in carbonate reservoirs at different diagenetic stages by using laboratory test, theoretical analysis, and numerical simulation research methods. The numerical simulation method is used to simulate the porosity changes and mineral evolution of reservoirs in different diagenetic stages, and the conclusion is drawn that meteoric water has an impact on reservoir minerals and porosity. The results show that the carbonate reservoirs in the Tarim Basin have high porosity and good permeability, and the reservoirs have experienced deposition, compaction, dissolution, and hydrothermal stages, and have experienced meteoric water effects for a long time, resulting in rock dissolution, regenerative precipitation and chemical reaction; Quartz and feldspar minerals are the most in the sample through laboratory tests, the content of quartz decreased first, then increased and decreased, and the content of chlorite and mica changed little during the whole diagenesis processes. With the injection of organic acid, the porosity of the reservoir increases, with the continuous increase of temperature and pressure, the porosity decreases. After the second injection of organic acid, the porosity increases continuously, and finally, the porosity decreases. TOUGHREACT is used to simulate the static reaction of water and rock, simulating six diagenetic stages. With the injection of organic acid, the porosity increases continuously and then reaches equilibrium. The sudden increase in temperature and pressure leads to an increase in porosity, and the porosity of the reservoir changes little during the second injection of organic acid, and the porosity decreases in the final stage. The research results provide theoretical data support for guiding oil and gas exploration in deep carbonate reservoirs.

Prospects for the use of flow diverter technologies at the Alibekmola oil field

Background: The process of oil production from low-permeability reservoirs has some features and is associated with a number of problems. The main problem is the lack of involvement in the active development of oil reserves in low-permeability zones. Most design documents for the development of low-permeability carbonate reservoirs recommend conventional water injection, which leads to rapid water encroachment of production wells due to water breakthrough from the injection well to the production well through the high-permeability layers or fractures.
 Aim: In the conditions of low-permeability reservoirs of carbonate deposits, there is a need to search for new technologies and development methods that will ensure the economic viability of field development at a late stage.
 Materials and methods: One of the promising technologies that help reduce the level of water cut and involve in the development of an inactive matrix zone low-permeability fractured reservoirs are flow diverter technologies aimed at increasing the sweeping efficiency of productive formations by redistributing filtration flows, reducing or stabilizing water cut, reducing the volume of produced water, obtaining additional oil production.
 Results: This article presents the results of laboratory studies on the selection of optimal flow diverter chemical compositions for the conditions of the Alibekmola oil field.
 Conclusion: Conducted laboratory studies prove the applicability and effectiveness of flow diverter compositions for the conditions of carbonate fractured reservoirs.

Research on key technology of packer rubber barrel for integrated fracturing and completion of gas well

The staged and layered fracturing technology plays an important role in unconventional tight reservoirs. And the gas well fracturing and completion integration is the core component to realize the fracturing and completion integration process, which can realize the integration of acid fracturing and later drainage production so as to reduce the secondary pollution to the reservoir. The packer rubber barrel’s performance directly affects the long-term effective sealing reliability itself in high temperature and high pressure environment. In this paper, the constitutive model of rubber tested from high temperature and high pressure curing kettle to simulate the high-temperature and highly corrosive environment of the formation. On this basis, the structure of the packer’s shoulder and the protective ring of the rubber barrels are optimized through Abaqus to reduce its stress failure under high pressure, and its corrosion resistance is improved by improving the rubber material. The sealing performance of the packer rubber cylinder under the field underground requirements is tested through laboratory evaluation test and field test. The results show that the protective ring and rubber tube shoulder at 30° angle are a reasonable result of optimization, and the optimized packer can meet the requirements of 154 °C temperature resistance, 79 MPa pressure bearing and long-term effective sealing. The successful development of packer rubber and the integrated analysis process can lay a solid foundation for the realization of integrated fracturing and completion process for exploration and development of deep volcanic or carbonate reservoirs.

Efficiency of maintaining reservoir pressure in oil wells during the development of carbonate reservoirs

The paper analyzes the operation dynamics of injection and observation production wells. It assesses the impact of injection wells on produced water density. The reservoir is characterized by out-contour flooding. It was found that such a scheme is ineffective due to the weak hydrodynamic relationship of the reservoir with the aquifer, which is confirmed by the result of this analysis, and the selective (focal) water flooding used on the Kizelovsky horizon also does not have the proper effect, and there is no correlation of formation pressure with injection in observation wells. It was shown that large volumes of water injection into injection wells do not maintain formation pressure in certain areas, but in general, there is a slight positive impact on the development indicators for the target. The recommendations for optimizing the formation pressure maintenance system were proposed based on the results of the analysis.

Improving oil and gas flowability in tight carbonates with a novel solid delayed acid

The economic development of tight carbonate reservoirs requires hydraulic or acid fracturing stimulation. Acid fracturing better activates natural fractures, resulting in increased stimulated reservoir volume and improving oil and gas flowability. In order to solve the problem of excessive acid-rock reaction due to high temperature, this paper screened four kinds of solid forms of acid with the maximum quantity of acid and reaction rate as the index and formed a high temperature-resistant mixed solid acid system with solid organic acid as the main part and inorganic solid acid as the auxiliary part. The maximum quantity of acid produced and effective acid concentration of the system were greater than 50%, and no residue was precipitated after the complete reaction. Dynamic acid-rock rate tests were performed on different types of retarded acid at 140 °C. The test results show that the solid acid dissolves to form a low-viscosity acid solution, and the reaction rate is one order of magnitude lower than that of gelled and cross-linked acids at the same hydrogen ion concentration, and it is little affected by temperature. Moreover, the paper compares the treatment effect of micro-proppants and solid acids on micro-fractures. The results show that the core permeability improvement multiples up to 900 times under low dissolution of solid acid and the formation of oil and gas flow channels with the same scale as micro-proppants. The experimental results demonstrated the ability of solid delayed acid to transport the fracture leading edge at high temperatures and effectively activate micro-fractures.

ABOUT SOME PROBLEMS OF WATERFLOODING IN CARBONATE RESERVOIRS

The features of waterflooding of carbonate (fractured-porous) rocks, caused by the interaction of the system of fractures with the matrix (blocks) of the rock, are considered. It is shown that the slower propagation of the pressure pulse in the rock matrix in comparison with the propagation of this pulse along the fracture system of the formation leads to compression of the rock blocks in the near-wellbore zone of the injection well, as a result of which stress concentration occurs at the ends of vertical fractures, which increases the likelihood of these fractures growing into the roof of the productive formation. It is shown that in order to prevent the development of this process, the growth rate of water injection pressure should be limited in accordance with the time of liquid pressure equalization in the pore space of the rock matrix and in the fracture system. When developing production wells drilled in fractured porous media, in order to prevent the development of the process of closing fractures in the bottomhole zones of these wells, the drawdown reduction rate must also be limited in a similar way. It is noted that when applying technologies for non-stationary flooding of productive reservoirs, the main factor determining their effectiveness is the change in the direction of filtration flows in the reservoir. This leads to the activation of filtration processes in the stagnant zones of the formation and the intensification of the processes of capillary impregnation of low-permeability interlayers with water from more flooded highpermeability interlayers.At the same time, it is important to take into account that when changing the direction of filtration flows at a late stage of development of carbonate reservoirs, in order to prevent reimpregnation of hydrophobic rock blocks with oil, it is more expedient to change the operating modes of production rather than injection wells. It is shown that water flooding of hydrophobic carbonate reservoirs results in incomplete water displacement of oil as a wetting phase from rock blocks. To reduce the residual oil saturation of rock blocks, it is advisable to increase the displacement pressure gradient in the reservoir in combination with a change in the direction of filtration flows in it.

Paleokarst caves recognition from seismic response simulation to convolutional neural network detection

Paleokarst systems, found in carbonate rock formations worldwide, have potential for creating vast reservoirs and facilitating hydrocarbon migration. Thus, studying these systems is essential for the exploration and development of carbonate reservoirs. An approach using convolutional neural networks (CNNs) is introduced to automatically and precisely identify cave features within 3D seismic data. An efficient technique is outlined for generating ample amounts of 3D training data, which is comprised of synthetic seismic data and labels for cave features contained in the seismic data, as a solution to bypass the labeling task for training the CNN. This workflow uses point-spread functions to simulate the cave response in the seismic data and allows us to easily generate realistic and diverse synthetic training data sets with different geologic structures and cave features. By training a CNN with these synthetic data sets, it can effectively learn to detect cave features in field seismic volumes. Upon evaluation using multiple examples, this approach outperforms earlier techniques like seismic attributes and other CNN-based paleokarst characterization methods.

Synthesis and Performance Evaluation of a Novel High-Temperature-Resistant Thickener.

Successful exploitation of carbonate reservoirs relies on the acid-fracturing process, while the thickeners used in this process play a key role. It is a common engineering problem that thickeners usually fail to function when used in high-temperature environments. Until now, no research has ventured into the field of synthesizing thickeners which can be effectively used at ultra-high temperatures up to 180 °C. In our current study, a novel high-temperature-resistant polyacrylamide thickener named SYGT has been developed. The thermal gravimetric analysis (TGA) reveals that SYGT is capable of withstanding temperatures of up to 300 °C. Both our scanning electron microscopy (SEM) and rheological analysis demonstrate that the SYGT exhibits excellent resistance to both temperature and shear. At 180 °C, the viscosity of the SYGT aqueous solution is no lower than 61.7 mPa·s at a 20% H+ concentration or high salt concentration, and the fracture conductivity of the thickened acid reaches 6 D·cm. For the first time, the influence of the polymer spatial network's structural parameters on the viscosity of polymer solutions has been evaluated quantitatively. It was discovered that the length and surrounding area of the SNS skeleton have a synergistic effect on the viscosity of the polymer solution. Our experiments show that SYGT effectively reduces the acid-rock reaction rate and filtration loss under harsh working conditions such as high temperature, strong shear, high salinity, and a high concentration of acid. The synthesized acid-fracturing thickener (SYGT) has wide application potential in the development of carbonate reservoirs under high-temperature conditions.