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Laboratory scale experiments have established LTG (Low Tension Gas) flooding to be a promising EOR method in low permeability and high salinity carbonate reservoirs for both tertiary and secondary recovery. In this work, three important factors that strongly influence the performance of LTG process are investigated: (i) wettability, (ii) injection gas type, and salinity variation. LTG flooding was investigated for the first time for low permeability carbonate cores, which had been aged for over five weeks after being oil flooded at residual water saturation (aged cores), and high formation brine salinity hardness. Hydrocarbon gas from the field was tested as a candidate for co-injection with surfactant solution to generate foam during LTG flooding. This eliminates the need for importing gas from an external source. Another innovation in the LTG process design is that the need for freshwater or treating the produced water from the field was removed by using the re-purposed high salinity produced water for all stages of the LTG flood. LTG floods in aged cores was observed to give oil recovery similar to non-aged cores under same conditions. LTG flood in aged cores resulted in a residual oil saturation of 11% compared to 19.4% using secondary WAG injection. [ABSTRACT FROM AUTHOR]

The natural fracture system plays a key role in the formation of hydrocarbon reservoirs in the carbonate buried hill of the Nanpu Sag in the Bohai Bay Basin, affecting the distribution of high-quality reservoirs and the migration and accumulation of hydrocarbons. Using data from outcrops, cores, thin sections, and image logs, a quantitative analysis was conducted on the development patterns of fractures both in vertical and horizontal directions, and the main controlling factors for fracture development were identified. On this basis, numerical simulation techniques were applied to quantitatively predict the development patterns of fractures in the carbonate reservoirs of the ancient buried hills in Nanpu Sag. Four types of fractures were identified in the study area: structural fractures, diagenetic fractures, weathering fractures, and dissolution fractures, with structural fractures being the most predominant. The fractures show a low degree of filling, with 59% being effective, indicating good fracture effectiveness. The linear density of structural fractures ranges from 3 to 10m-1, with an average of 5.6m-1. The height of structural fractures is generally less than 30 cm, mainly distributed between 5 and 20 cm. The microscopic fracture areal density ranges from 25 to 50 cm/cm², with an average of 32.3 cm/cm², and the porosity of micro-fractures ranges from 0.24% to 0.69%, averaging at 0.55%. These micro-fractures provide essential storage space in tight reservoirs and enhance pore connectivity, facilitating hydrocarbon migration and accumulation. Three primary fracture groups were identified in the study area: nearly E-Wtrending fractures, NE-SWtrending fractures, and NW-SE trending fractures, with the first two groups being the most developed. The degree of fracture development in the study area is mainly affected by lithology, rock mechanical layers, and faults. Fractures are most abundant in dolomite and dolomitic limestone, but less developed in mudstone. Different rock mechanical interfaces affect the geometry, scale, and intensity of fracture development. Stratigraphy-bound fractures are generally vertical and terminate at rockmechanical interfaces, while throughgoing fractures usually spanmultiplemechanical layers and are controlled by more extensivemechanical interfaces. Faults are important factor in fracture heterogeneity, with fracture intensity being highest near fault cores, especially at fault tips, overlaps, intersections, and the hinges of fault-associated folds. The number of fractures decreases as the distance fromthe fault zone increases. [ABSTRACT FROM AUTHOR]

Copyright of Petroleum Geology & Recovery Efficiency is the property of Petroleum Geology & Recovery Efficiency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

The prediction accuracy of favorable fracture-cavity zones and reservoir development can be effectively improved through the quantitative classification of fracture-cavity bodies. The classification and grading of internal faults within fracture-cavity bodies were explored by applying fracture development models, fracture scale classification, and stress analysis based on structural curvature. A comprehensive classification of amplitude and wave impedance was undertaken, followed by large-sample calibration and verification with the aim of establishing a karst-cave grading standard. As an illustrative example, a specific area in Tahe was employed. The fault zone in this area was divided into eight grades based on its scale and stress properties. Indications from real drilling data show that the reservoir performance in the extension area is significantly better than that in the compression area. Additionally, the threshold value of seismic attributes for hole-cave classification was established within this study area. The specified energy ratio range of “ beads-on- string” features is 54% ~ 62% for holes, and the energy ratio exceeds 62% for karst caves. Ultimately, the reliability of this technology was confirmed through real drilling analysis. [ABSTRACT FROM AUTHOR]

Laboratory filtration experiments are employed to investigate effective well killing while minimizing its impacts on surrounding rocks. The novelty of this experimental study lies in the prolonged exposure of rock samples to the killing fluid for seven days, corresponding to the average duration of well workovers in the oilfields in Perm Krai, Russia. Our findings indicate that critical factors influencing the interactions between rocks and the killing fluid include the chemical composition of the killing fluid, the mineralogical composition of the carbonate rocks, reservoir pressure and temperature, and the contact time. Petrophysical analyses using multi-scale X-ray computed tomography, field emission scanning electron microscopy, and X-ray diffraction were conducted on samples both before and after the well killing simulation. The experiments were performed using real samples of cores, crude oil, and the killing fluid. The results from this study indicate that low-mineralized water (practically fresh water) is a carbonate rock solvent. Such water causes the dissolution of rock components, the formation of new calcite crystals and amoeba-like secretions, and the migration of small particles (clay, quartz, and carbonates). The formation of deep channels was also recorded. The assessment reveals that the change in the pH of the killing fluid indicates that the observed mineral reactions were caused by carbonate dissolution. These combined phenomena led to a decrease in the total number of voids in the core samples, which was 25% on average, predominantly among voids measuring between 45 and 70 μm in size. The change in the pore distribution in the bulk of the samples resulted in decreases in porosity of 1.8% and permeability of 67.0% in the studied core samples. The results from this study indicate the unsuitability of lowmineralized water as a well killing fluid in carbonate reservoirs. The composition of the killing fluid should be optimized, for example, in terms of the ionic composition of water, which we intend to investigate in future research. [ABSTRACT FROM AUTHOR]

In Brazil, pre-salt carbonate reservoirs are largely responsible for the current increase in oil production. However, due to its peculiar characteristics, increasing oil recovery by water injection is not enough. Therefore, we seek to evaluate the recovery potential using chemical methods (cEOR). Among these, the Alkali Surfactant Foam (ASF) method appears with high potential, a variant of Alkali Surfactant Polymers (ASP) without the problems presented by it. Therefore, this work presents an innovative methodology, which seeks to evaluate the potential for recovery with ASF in carbonate reservoirs by integrating experimental characterization and recovery prediction using reservoir simulation. For this, phase behavior and adsorption analyses were carried out. The experimental results provided key parameters for the simulation, such as optimal salinity, surfactant adsorption, foam mobility reduction factors. The results are from two case studies of AS and ASF flooding, using a section of UNISIM-II benchmark, using a one-quarter of five-spot model. Having the modelling for these cEOR methods defined, an optimization process for each method was applied, allowing a reliable comparison among the methods and over a base case of water injection, seeking the maximization of the net present value (NPV). As a result, in the experimental part, a low interfacial tension (IFT) value of 0.003 mN/m was achieved with a surfactant adsorption reduction of 17.9% for an optimal setting among brine (NaCl), alkali (NaBO2.4H2O), and surfactant (BIO-TERGE AS 40). In the reservoir simulation part, using a fast genetic algorithm in the optimization process, a NPV of US$ 14.43 million higher than the base case (water injection) and a 4.5% increase in cumulative oil production for the ASF injection case were obtained. Considering the analyses of production curves (cumulative oil production and oil rate) and oil saturation maps, a considerable oil production anticipation was observed, which was the main reason for NPV improvement, proving the high potential for application of the ASF method in carbonate reservoirs. [ABSTRACT FROM AUTHOR]

Fractured-vuggy carbonate reservoirs are characterized by low porosity， low permeability， and strong heterogeneity. Acid fracturing is the primary technical means to increase the production of this kind of reservoir， and the key to fracturing reconstruction is to communicate fractured-vuggy reservoir efficiently. However， due to the influence of heterogeneity and randomly distributed vugs， the fracture propagation paths are complicated during acid fracturing， and the law of fracture-vug interaction is not clear. Therefore， laboratory experiments were carried out to study the changes in porosity， permeability， and mechanical properties of carbonate rocks before and after acid etching. The experimental results showed that acid-rock reaction significantly influences rock mechanics parameters. With a 15% mass fraction of gelled acid as an example， core porosity and permeability increase； the compressive strength and elastic modulus of cores decrease by 42% and 60%， and Poisson’s ratio increases by 25% after acid etching. Then， the rock’s physical and mechanical evolution equation was introduced into the classical cohesive model， and a fracture propagation model considering acid-rock reaction was established. The model was compared with the conventional hydraulic fracture propagation model and the laboratory physical simulation experiment of acid fracturing， and the effectiveness and correctness of the model were verified. Finally， the model was used to study the effects of horizontal in-situ stress difference， vug size， and injection displacement on fracture propagation path. The simulation results showed that ① Artificial fractures tend to penetrate small vugs， bypass medium vugs， and communicate with large vugs. ②It is helpful for the communication between fractures and vugs when the horizontal stress difference exceeds 5 MPa and the injection displacement exceeds 0.057 m3/s. ③ The acid-rock reaction can significantly improve the fractured-vuggy communication efficiency， and the fracture propagation area by acid fracturing is twice that by conventional hydraulic fracturing when the injection displacement is 0.1 m3/s. Therefore， in order to improve the fractured-vuggy communication efficiency and acid fracturing effect， the injection displacement should be appropriately increased when stimulating the carbonate reservoir with high stress difference.

The Jialingjiang Formation is a traditional stratum for natural gas exploration in the Sichuan Basin, and in recent years it has been continuously discovered in northern and southwestern Sichuan, but there are still large areas of exploration blanks in the basin, which urgently needs to deepen the understanding of the natural gas accumulation law of this formation, clarify the main controlling factors of the accumulation, and then point out the exploration direction in the future. By using natural gas geochemistry and other analytical tests, combined with structural restoration, basin simulation and other technologies, based on gas source analysis, with typical gas reservoir anatomy as the core, combined with the understanding of the reservoir conditions of the Jialingjiang Formation, the main controlling factors of reservoir formation were discussed through the analysis of reservoir formation process, and the reservoir formation model was established. The results show that the natural gas of the Jialingjiang Formation is mainly cracked gas from crude oil in the lower part. The Jialingjiang Formation has good reservoir formation conditions such as multiple sets of high-quality source rocks supplying hydrocarbons, developing multiple types of carbonate reservoirs, and source-connected faults that effectively communicate gas sources. The paleostructures of the main oil generation period, the structures of the adjustment period, the source-connected faults, and the favorable reservoir types are the main controlling factors of the natural gas accumulation in the Jialingjiang Formation in the Sichuan Basin. The Jialingjiang Formation has an accumulation model of "multi-source charging to form ancient oil reservoirs, ancient oil reservoir cracking and supply gas, source-connected faults transport, and late adjustment accumulation". Based on this, it is proposed that the structural and litholo-gical composite gas reservoirs distributed in the piedmont belts of western and northern Sichuan, which are at relatively high positions during the main oil generation period and gas reservoir adjustment and accumulation period, have developed source-connecting faults, and have good preservation conditions, are the preferred exploration directions. The porous lithological gas reservoirs distributed in the structurally stable areas and syncline areas of the high and steep structural belts in eastern Sichuan are the main exploration directions in the future.

Abstract In Brazil, pre-salt carbonate reservoirs are largely responsible for the current increase in oil production. However, due to its peculiar characteristics, increasing oil recovery by water injection is not enough. Therefore, we seek to evaluate the recovery potential using chemical methods (cEOR). Among these, the Alkali Surfactant Foam (ASF) method appears with high potential, a variant of Alkali Surfactant Polymers (ASP) without the problems presented by it. Therefore, this work presents an innovative methodology, which seeks to evaluate the potential for recovery with ASF in carbonate reservoirs by integrating experimental characterization and recovery prediction using reservoir simulation. For this, phase behavior and adsorption analyses were carried out. The experimental results provided key parameters for the simulation, such as optimal salinity, surfactant adsorption, foam mobility reduction factors. The results are from two case studies of AS and ASF flooding, using a section of UNISIM-II benchmark, using a one-quarter of five-spot model. Having the modelling for these cEOR methods defined, an optimization process for each method was applied, allowing a reliable comparison among the methods and over a base case of water injection, seeking the maximization of the net present value (NPV). As a result, in the experimental part, a low interfacial tension (IFT) value of 0.003 mN/m was achieved with a surfactant adsorption reduction of 17.9% for an optimal setting among brine (NaCl), alkali (NaBO2.4H2O), and surfactant (BIO-TERGE AS 40). In the reservoir simulation part, using a fast genetic algorithm in the optimization process, a NPV of US$ 14.43 million higher than the base case (water injection) and a 4.5% increase in cumulative oil production for the ASF injection case were obtained. Considering the analyses of production curves (cumulative oil production and oil rate) and oil saturation maps, a considerable oil production anticipation was observed, which was the main reason for NPV improvement, proving the high potential for application of the ASF method in carbonate reservoirs.

Copyright of Petroleum Geology & Experiment is the property of Petroleum Geology & Experiment Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

In situ-generated acid is commonly employed in ultra-deep, high-temperature carbonate reservoirs during acid fracturing to increase the effective acid penetration distance. However, the variation pattern of acid-etched fracture conductivity with in situ-generated acid has not been systematically studied. This paper investigates the evolution of the conductivity of primary and secondary fractures through a series of experiments involving in situ acid displacement and acid-etched fracture conductivity measurement. Based on the experimental results, a calculation model for the conductivity of acid-etched fractures with in situ-generated acid was established. The study indicates that after acid etching, rough particulate points and grooved dissolution patterns form on the surfaces of primary and secondary fractures, respectively. The dissolution volume in primary fractures is greater than that in secondary fractures, with both showing a linear increase over time. Due to the presence of dissolution grooves on the surfaces of secondary fractures, their conductivity is higher than that of primary fractures under the same acid–rock contact time. The conductivity of both primary and secondary fractures increases with the acid–rock contact time. However, beyond approximately 70 min of contact time, the conductivity of primary fractures shows no significant increase. The conductivity of primary and secondary fractures with in situ-generated acid is slightly lower than that with gelled acid under the same contact time, but significantly higher than that with crosslinked acid. This study provides guidance for the design and parameter optimization of acid fracturing in ultra-deep, high-temperature carbonate reservoirs. [ABSTRACT FROM AUTHOR]

Carbonate reservoir of Kais Formation in Salawati Basin, West Papua, is the most famous oil and gas reservoir in the eastern part of Indonesian Archipelago since 1970's. Nowadays, new prospects in this area are more challenging and most relevant near the infrastructure of previous oil and gas fields. In this study, a relatively new seismic dataset was investigated to figure out new prospects in carbonate reservoir rocks in the area of interest. In this preliminary study, where seismic data are not supported by well data, direct hydrocarbon indicator (DHI), seismic attribute, and spectral decomposition (CWT: continuous wavelet transform) allow the authors to characterize the reservoir geometry and to predict pore fluids within the reservoir rocks. The reservoir geometry of carbonate reef of Kais Formation (C1) was identified by seismic reflectors with high amplitude contrast at the top C1. The hydrocarbon indicator was predicted by DHI where dim spots, flat spots, and polarity reversals are indicative of hydrocarbon prospects. From the attribute analysis, the attribute instantaneous amplitude detected the top carbonate C1, whereas pore fluids were predicted from high sweetness attribute. In addition, spectral decomposition CWT method confirms the top C1, identified as saturated rock by the frequency of 10 Hz, 20 Hz, and 30 Hz. Based on a seismic study in the researched area, the target zone is expected to be a very promising hydrocarbon reservoir, specifically a carbonate reservoir. As a result, the preferred well-test location is in a region with access to the Kais Formation limestone reef layer. This study can assist in reservoir characterization, especially in areas with limited well control. [ABSTRACT FROM AUTHOR]

The carbonate reservoirs of Cenomanian–Early Turonian in the northeastern Central Arabian Basin hold considerable oil reserves and are great contributors to oil production. Diagenesis have a great impact on carbonate reservoir petrophysical properties, microstructure, and heterogeneity. By integrating cores, cast thin sections, regular core analysis, CT, and isotopes, this study provides an improved understanding of diagenesis in the Cenomanian–Early Turonian and its effect on carbonate reservoirs. The results showed that three diagenetic environments were identified in the Cenomanian–Early Turonian based on texture, structure, cement, crystal form, and crystal size, which were marine environment, meteoric environment, and burial environment. Six diageneses were identified based on residual bioclastic, secondary pores, calcite quantity, dolomite size, and stylolite, namely dissolution, cementation, micritization, dolomitization, compaction, and pressure solution. A micritization model in high energy sediment, a dolomitization model in burrows, and a comprehensive diagenetic model were established. It concluded that dissolution during meteoric environment is most favorable to reservoir physical properties, while cementation is least favorable. The cement content controls the microstructure and petrophysical property. Micritization is detrimental to the petrophysical properties, and the micrite it forms are distributed in the interparticle pores, reducing the reservoir property deposited in high energy environment. Dolomitization is less developed in substrate but widely developed in burrows, which result in the physical properties of the burrows being higher than those of substrate. Compaction and pressure solution have a negative impact on reservoir physical properties. [ABSTRACT FROM AUTHOR]

Building a reliable and accurate geological model for a carbonate reservoir poses extreme challenges in reservoir modeling studies that lead to higher uncertainty levels for field development plans. Consequently, economic viability studies for the field will suffer from low confidence levels. The improper geological interpretation for reservoir heterogeneity may lead to project failure. This study presents an integrated geological model building, evaluation, and demonstrating results of the Shuaiba reservoir in the Khabaz field by highlighting a practical approach. The geological analysis included an evaluation of the structure, determination, and consideration of the deposition environment. A robust facies model was generated to capture the lateral and vertical reservoir heterogeneity. This leads to accurate reservoir characterization of reservoir heterogeneity by establishing a reservoir model conditioning to well observations which is called explicitly modeling of known heterogeneities. The mathematical and statistical algorithms are used to systematically simulate the spatial distribution of reservoir properties at inter-well locations. [ABSTRACT FROM AUTHOR]

A comprehensive drilling of wells has been conducted in the Permian Qixia Formation in the central Sichuan Basin, revealing a significant number of dolomite reservoirs. High- and medium-porosity dolomite reservoirs are the main gas-producing reservoirs in the Qixia Formation. Seismic PP-wave data show a "bright spot" for high-porosity dolomite reservoir formations but weak responses for medium-porosity dolomite reservoir formations, which is attributed to the inability of P waves to distinguish between medium-porosity reservoirs and limestone. However, medium-porosity dolomite and limestone have different S-wave velocities. Therefore, in this study, the identification of different-porosity dolomite reservoirs using multi-component seismic data was investigated. A comprehensive analysis of the elastic waves by forward modeling shows that the PS-wave amplitude is more sensitive to medium-porosity dolomite than the PP-wave amplitude. Therefore, medium-porosity dolomite reservoirs can be predicted using the amplitude attributes of the PS-wave, and high-porosity dolomite reservoirs can be characterized using the PP-wave. Meanwhile, the elastic parameter λρ (the product of Lame constant λ and density ρ), which is highly correlated with the dolomite content, can be used as an indicator of dolomite formations. Furthermore, compared to the results of PP-wave inversion, the elastic parameters derived from the joint inversion of PP- and PS-waves exhibited a better correspondence with the well-logging results. The comprehensive use of the seismic amplitude responses of PP- and PS-waves and multi-component seismic joint inversion can effectively predict high- and medium-porosity dolomite reservoirs. The predicted results can support the exploration and development of the Qixia Formation. [ABSTRACT FROM AUTHOR]

The complex pore structure of carbonate reservoirs hinders the correlation between porosity and permeability. In view of the sedimentation, diagenesis, testing, and production characteristics of carbonate reservoirs in the study area, combined with the current trends and advances in well log interpretation techniques for carbonate reservoirs, a log interpretation technology route of "geological information constraint þ deep learning" was developed. The principal component analysis (PCA) was employed to establish lithology identification criteria with an accuracy of 91%. The Bayesian stepwise discriminant method was used to construct a sedimentary microfacies identification method with an accuracy of 90.5%. Based on production data, the main lithologies and sedimentary microfacies of effective reservoirs were determined, and 10 petrophysical facies with effective reservoir characteristics were identified. Constrained by petrophysical facies, the mean interpretation error of porosity compared to core analysis results is 2.7%, and the ratio of interpreted permeability to core analysis is within one order of magnitude, averaging 3.6. The research results demonstrate that deep learning algorithms can uncover the correlation in carbonate reservoir well logging data. Integrating geological and production data and selecting appropriate machine learning algorithms can significantly improve the accuracy of well log interpretation for carbonate reservoirs. [ABSTRACT FROM AUTHOR]

Low-salinity water flooding has recently garnered attention in carbonate formations mainly due to the cost-effectiveness of this improved oil recovery technique. Despite recent work in this area, the underlying mechanism remains controversial, thereby limiting field implementation. Low-salinity water flooding in limestone formations has been less explored and, hence, less understood in improved oil recovery (IOR) literature. The mechanisms leading to improved recovery are mostly attributed to wettability alteration, with less attention given to fluid–fluid interaction mechanisms. Results demonstrate that the existing cations in the Third River have a significant effect on wettability alteration, reducing it from 103° to 45° after immersing carbonate rock samples for 40 min. This is a promising result towards enhanced water wetness and oil recovery. This study is one of the first conducted in the Nassiriyah oil field to investigate the potential for IOR using the Third River (low salinity water). The current work highlighted the underlying mechanism behind the low-salinity water flooding effect in carbonate rocks by investigating the role of ions in the Third River that flows adjacent to the Nassiriyah oil field. [ABSTRACT FROM AUTHOR]

This study aims to predict Yamama layers formation permeability of five wells: N1, N2, N3, N4, and N5, each containing Yamama, Yamama B and Yamama C layers. The permeability was calculated through two methods, namely the basic analysis and well-log techniques. The basic analysis method was conducted in the laboratory using a PERL-200 device. The results obtained using this method were more accurate as they matched the well-log results. Employing Matlab software, a neural network predicted permeability for 14 layers of 5 wells, with the second and fifth wells having only two layers. By constructing a 13-layer neural network, an appropriate network configuration can be achieved to discover the relationship between the input and output and produce a matching target result. [ABSTRACT FROM AUTHOR]

The homogeneous acid etching of conventional acid in porous heterogeneous carbonate reservoirs leads to a large amount of consumption in the near-wellbore area, which makes the acidification effect often not ideal. In order to improve the acidizing effect of porous heterogeneous carbonate reservoirs, viscous acid is used to increase the stimulation of the target block in this paper. Through systematic experiments, the adaptability of the viscous acid in the four layers of the M reservoir in the target block was evaluated, and the MD and ME layers suitable for acidizing stimulation were determined in combination with physical property analysis. Finally, based on the geological characteristics and experimental data of the preferred layers, a two-scale acid wormhole growth radial model was established, and the construction parameters of acidizing stimulation were optimized. The results show that (1) The preferred viscous acid system has a dissolution rate of more than 95% for the rock powder in the four layers. When the matrix permeability is high, the effect of the acid wormhole is obvious and the permeability increase is higher. (2) The steel sheet corrosion and residual acid damage experiments showed that the acid system was not corrosive to the wellbore, and the reservoir damage rate of the residual acid after the reaction was low. (3) Based on the relationship between reservoir porosity and permeability and the position of edge and bottom water, the MD and ME layers with more potential for acidizing stimulation are selected. (4) The results of the numerical simulation show that the optimal acid pump rate of the MD and ME layers is 1.4 bpm and 1.0 bpm, and the acidizing fluid volume is 255 bbl, which can form effective acid wormholes, and the range of reservoir permeability transformation is the largest. The field application results show that the optimization scheme effectively improves the production of oil wells, verifies the practicability of the scheme, and provides a reference for the process optimization of viscous acid in the same type of porous heterogeneous carbonate reservoir stimulation. [ABSTRACT FROM AUTHOR]

Hybrid deposits form from the interaction between carbonate deposition and coeval siliciclastic input, influenced by spatial and temporal dynamics. This interaction occurs across various mixing scales, resulting in a high vertical and lateral lithological variability. Understanding this heterogeneity is crucial for comprehending and modelling hybrid reservoirs. The Albian succession of the SE Brazilian margin records the early evolution of the South Atlantic Ocean. In the Campos Basin, this interval is represented by a retrograding succession of shallow-marine carbonates (Quissamã Formation) overlain by deep marine calcilutites and shales. We use cored wells, petrographic thin sections and geophysical logs to detail the Albian in the SW Campos Basin, to characterize its depositional model and stratigraphical succession. We identified four facies associations that define different parts of a hybrid carbonate–siliciclastic ramp: carbonate shoal (subdivided into shallower and deeper portions), hybrid carbonate-siliciclastic shoal, and coastal environment. Carbonate shoals are composed of calcarenites and calcirudites with oolites, oncolites, peloids, bioclasts and intraclasts. Hybrid shoals also present calcarenites and calcirudites but include a significant siliciclastic fraction. Coastal environments are dominantly composed of hybrid arenites, locally dolomitized. Carbonate-siliciclastic mixing occurs at different scales: compositional mixing at bed scale, and strata mixing at lithofacies and stratigraphic scales. This sediment mixture results from the interaction between waves, currents, base-level variation cycles, and salt tectonics. Isolith maps of siliciclastic and carbonate facies of the Quissamã Formation reveal four NE-trending shoals aligned on a NW-SE trend. Chronostratigraphic analysis indicates that the shoals were non-contemporary, with the most distal shoal forming earlier, indicating a retrograding, backstepping pattern for the Albian in the Campos Basin.

Laboratory filtration experiments are employed to investigate effective well killing while minimizing its impacts on surrounding rocks. The novelty of this experimental study lies in the prolonged exposure of rock samples to the killing fluid for seven days, corresponding to the average duration of well workovers in the oilfields in Perm Krai, Russia. Our findings indicate that critical factors influencing the interactions between rocks and the killing fluid include the chemical composition of the killing fluid, the mineralogical composition of the carbonate rocks, reservoir pressure and temperature, and the contact time. Petrophysical analyses using multi-scale X-ray computed tomography, field emission scanning electron microscopy, and X-ray diffraction were conducted on samples both before and after the well killing simulation. The experiments were performed using real samples of cores, crude oil, and the killing fluid. The results from this study indicate that low-mineralized water (practically fresh water) is a carbonate rock solvent. Such water causes the dissolution of rock components, the formation of new calcite crystals and amoeba-like secretions, and the migration of small particles (clay, quartz, and carbonates). The formation of deep channels was also recorded. The assessment reveals that the change in the pH of the killing fluid indicates that the observed mineral reactions were caused by carbonate dissolution. These combined phenomena led to a decrease in the total number of voids in the core samples, which was 25% on average, predominantly among voids measuring between 45 and 70 μm in size. The change in the pore distribution in the bulk of the samples resulted in decreases in porosity of 1.8% and permeability of 67.0% in the studied core samples. The results from this study indicate the unsuitability of low-mineralized water as a well killing fluid in carbonate reservoirs. The composition of the killing fluid should be optimized, for example, in terms of the ionic composition of water, which we intend to investigate in future research.

The paper presents the results of experimental evaluation of oil displacement efficiency by flue gas of a thermal power plant, compared to water, for a carbonate reservoir in the Ural-Volga region. The experiments were performed under two different injection schemes using an original laboratory complex for coreflood studies, with recombined reservoir oil, model of formation water, reservoir core material, and under reservoir thermobaric conditions. It has been confirmed that due to the prevailing nitrogen content and low values of reservoir pressure and temperature, flue gas is ineffective as an independent displacement agent either for injection from the beginning of reservoir development or as a tertiary method after waterflooding. Taking into account the relevance of synergy between increasing oil recovery and sequestration of industrial emissions, evaluation of flue gas injection as part of water-gas mixtures (SWAG) is recommended.

Objective Calcite veins are the products of tectonic diagenesis. Information about fracture opening and fluid activity was recorded by calcite veins. Methods Multiple approaches, consisting of thin section observation, cathodoluminescence, U-Pb isotope dating, and REE, C, O and Sr isotope analyses of calcite veins from the Triassic Qinglong carbonate reservoirs in the Huangqiao area, Subei Basin, are used to analyse the origin of vein-forming fluid. Results Four stages of calcite veins were identified in the Qinglong Formation and successively formed at (115.30±0.42), (97.03±0.43), (85.29±0.25), (45.5±19.0) Ma. In the first stage, the calcite veins were derived from deep hydrothermal fluids.And in the second stage, the calcite veins were derived from mixed fluids of atmospheric fresh water and seawater. Formation water and deep shell-source hydrothermal fluid mixed in the vein-forming fluid of the third-stage calcite veins. In the fourth stage of calcite veins formation, deep mantle-source hydrothermal fluid mixed with the formation water, resulting in the precipitation of calcite veins. The formation timing of the four stages of calcite veins corresponds to multistage tectonic movements during different periods, indicating that fluid evolution in the Triassic Qinglong carbonate reservoirs was controlled by multiple stages of tectonic movements. Conclusion Importantly, three stages of deep hydrothermal fluid injectionin the reservoir were the result of deep fault opening caused by tectonic movements, which possibly indicate multistage hydrocarbon accumulation in the Triassic Qinglong Formation in the Huangqiao area.

This paper proposes a method for determining the boundary values of open porosity (KPO_GR) and gas permeability (KPR_GR) of porous-type carbonate reservoir rocks using the example of Tournaisian deposits of one of the oil fields of the Republic of Tatarstan. When justifying the boundary values, two databases on core studies are used: 1) on standard core studies (used mainly to calculate hydrocarbon (HC) reserves); 2) on special core studies (used for technological development projects). In the proposed method, the residual oil saturation factor is not a constant, but is taken from flow studies or calculated from core dependencies. When determining the lower limits of porosity and permeability from both databases, approximately the same boundary values were obtained: KPO_GR = 0.11 fr. un., KPR_GR = 2·10–3 μm2 and KPR_GR = 1.7·10–3 μm2 , but they differ from the values, accepted by petrophysicists when calculating the reserves of considered deposit – KPO_GR = 0.09 fr. un., KPR_GR = 1·10–3 μm2 . Such a difference in determining the boundary porosity can significantly affect the calculation of hydrocarbon reserves, technological calculations and field development planning.

The majority of reserves of small oil companies of the Republic of Tatarstan are represented by carbonate reservoirs with low filtration and capacitance properties, low reservoir pressures and high oil viscosity. All this leads to a rapid decrease and a low level of current oil flows. The Akan oil field of Predpriyatie Kara Altyn CJSC is one of the examples. Thermal methods are considered as the most effective technologies for deposits with high-viscosity oil. According to the results of laboratory study of various variants of thermal methods and geological and hydrodynamic modeling, the steam-cyclic method of development was determined as the most effective at the Akan field. Two producing directional wells and two horizontal wells have been selected for experimental work on steam injection. The article considers the downhole equipment used for injection heat carrier, describes the process of steam injection with the dynamics of controlled parameters, production indicators and efficiency after heat treatment of wells. Conclusions are presented for the completed works on wells.

To date, significant foreign and domestic experience has been accumulated in the construction and operation of horizontal, multilateral and multilateral wells, as well as the restoration of an idle well stock by drilling sidetracks and sidetracks into various productive formations: low-permeability and highly dissected, with low values of effective oil-saturated thicknesses, degraded hydrodynamic connection with the contour area, etc. In this regard, it becomes extremely important to make a decision on choosing the optimal well profile in specific geological and physical conditions. The relevance of the work is also confirmed by the fact that at some development sites there is a decrease in the oil production rate of horizontal wells to the level of directional wells in the initial period of operation. Based on a significant difference in the reservoir properties of oil fields in the Perm Territory, all the analyzed objects operated by horizontal wells are combined into several groups: “northern” (N) and two “southern” (S1 and S2 ). The main parameter in the selection of groups was the coefficient of mobility of oil. The well-by-well technical and economic assessment performed in the article, based on the actual values of production over a long period, made it possible to identify the optimal well profile depending on the geological and physical characteristics of the reservoir. Combining the main geological characteristics that affect the technological parameters of well operation, with an economic assessment, the dependences of the net present value on the formation hydraulic conductivity were built. Dependences built for the first time make it possible to reasonably select the well profile in specific geological and physical conditions. Also in the work for a variety of geological and physical conditions, the value of the minimum profitable oil production for various well profiles is determined. Thus, the basis has been created, which is necessary for determining the profile of wells when planning production drilling.

The proposed method of predicting spatial distribution of leaching zones in carbonate reservoirs includes integrated interpretation of well logging data, including electrical microimages (Formation MicroImager – FMI), together with analysis of lithofacies within depositional cycles. Based on the comparison of FMI data with results of lithological and petrophysical studies of the core, an atlas of diagenetic porosity images for the studied formation was developed. Choquette and Pray international classification was used for pore typing. Applying the developed atlas to FMI logs, karstification zones were identified and classified in reference wells. In wells, where only standard well loggings was performed, karstification zones were identified using a developed decision tree. Sedimentological and sequence stratigraphic analysis made it possible to identify sedimentation cycles and to correlate the main lithofacies within the target reservoir. It was established that microbial and shallow facies form the most productive part of the reservoir. These facies with initially high primary porosity were subjected to the most intensive karstification along sequence stratigraphic boundaries due to subaerial exposure. The established relationships between leaching zones, lithofacies, and sequence-stratigraphic boundaries made it possible to carry out inter-well correlation of karstified intervals. The correlation will allow construction of leaching zones maps, that will be further applied for geological modeling.

At present, a large number of scientific works devoted to the study of the features of the geological structure and the development of oil deposits in complex carbonate reservoirs are based on the use of any one research method. This article shows the advantages of the integrated use of modern methods of core research, including X-ray microtomography and electron microscopy, as well as data from hydrodynamic and field studies of wells. The advantage of the approach used is the ability to study the deposit at three levels: core-well-development object, it is reasonable to transfer micro-survey data to the regularities of the implementation of technological processes of oil production. The objects of research in this article are the Famennian oil deposits of two neighboring fields, which, at first glance, are analogues in terms of the similarity of the enlarged geological and physical characteristics. Comprehensive studies of core samples from these deposits made it possible to establish differences both in the mineral composition of rocks and in the structure of their void space, especially in the size and distribution of pore channels. So, with approximately equal porosity for one of the deposits, the presence of two types of voids and a twofold prevalence of the size of the largest of them were established. According to the complex of laboratory methods for studying the core, the reservoir is classified as a porous type (no cracks were found). The performed interpretation of the hydrodynamic studies confirmed this fact, made it possible to establish the presence of a dependence of the reservoir permeability on the formation pressure (deformation of the void space of the reservoir), and also to build the corresponding individual dependence for each well. Comparison of the equations approximating the dependence data showed a more pronounced deformation of the reservoir, which is characterized by the presence of large pores and caverns. That is, a complex of laboratory and hydrodynamic studies made it possible to establish the probability of deformation of the void space of a carbonate reservoir even in the absence of cracks in it. In turn, the reservoir deformation is singled out as the most probable cause explaining the different rates of decline in well flow rates of the fields under consideration.

The use of the electron paramagnetic resonance (EPR) method for studying carbonate rocks is widespread. EPR makes it possible to reconstruct lithological and geochemical environments of ancient sedimentation, including redox conditions and paleo-radioactivity of sedimentation basins. The paper considers the heterogeneous structure of carbonate reservoir rocks of the Kazanian Stage of the Gorsky ultraviscous oil field by paramagnetic marks: manganese ions Mn2+, radical ions SO3 – , SO2 – , РO2 2-(РO2 0 ) in carbonate minerals and radical С600 in the remains of organic matter in the rock. The carbonate reservoirs of the Gorsky structure, tectonically confined to the eastern side of the Melekess Depression, are represented by two main lithotypes: dolomitic boundstones and dolomitic oolitic packstones, which have various post-sedimentary alterations. EPR data were obtained for 28 samples with a step of 0.5- 1.5 m along the section. The EPR spectra are characterized by narrow lines that indicate the marine origin of carbonates. Based on the EPR spectra of the ions Mn2+ and its content in carbonate minerals, the lagoonal-marine genesis of the Gorsky structure rocks was revealed. The dominant dolomite mineralization of the section was established. The absence of dolomite radicals and low values of the degree of population of the magnesium and calcium positions of dolomites are due to the secondary nature of carbonates. The distribution of manganese ions, organic and inorganic radicals in the rock along the section is shown simultaneously with its reservoir properties and the conditions for the formation of two dolomite lithotypes.

CO2 is being considered as an effective alternative working fluid for geothermal applications due to its superior fluid dynamics and heat transfer properties compared to water. Utilizing sedimentary rocks for geothermal energy recovery through a CO2-plume geothermal system, especially in carbonate reservoirs, has been shown to be a practical approach that eliminates the need for hydraulic fracturing. However, uncertainties remain regarding the thermal and hydraulic behavior, particularly the chemical interactions between CO2 and carbonate rocks. This study develops a comprehensive wellbore–reservoir coupling reactive transport model based on specific information obtained from the Ordovician limestone geothermal reservoir in Shandong, China. The model aims to assess the feasibility of heat extraction in carbonate reservoirs by evaluating the heat extraction performance and fluid–rock interaction. The results indicate a rapid temperature drop after CO2 breakthrough due to the Joule–Thomson effect. Simultaneously, the fluid transitions into and maintains a two-phase state throughout the operation. Chemical reactions within the reservoir are not aggressive since complete mixing between unsaturated water and CO2 only occurs in the vicinity of the production well, highlighting the potential of utilizing carbonate reservoirs for efficient heat extraction in geothermal systems. Further research is needed to optimize the performance of CO2-based geothermal systems in carbonate reservoirs. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

The aim of this study was to characterize the influence of CO2 in geological structures on mineralogical changes in rocks and assess the sequestration capacity in mineral form and solution of a potential pilot storage site in the Czech Republic. Rock samples from a dolomite reservoir and the overburden level, as well as the corresponding pore water, were used. The most important chemical process occurring in the reservoir rock is the dissolution of carbonate minerals and feldspars during the injection of CO2 into the structure, which increases the porosity of the structure by approximately 0.25 percentage points and affects the sequestration capacity of the reservoir rock. According to the results of geochemical modeling, the secondary carbonate minerals (dolomite, siderite, and ephemeral dawsonite) were present only during the first 50 years of storage, and the porosity at this stage decreased by 1.20 pp. In the caprocks, the decomposition of K-feldspar and calcite resulted in an increase in porosity by 0.15 percentage points at the injection stage only, while no changes in porosity were noted during storage. This suggests that their insulation efficiency can be maintained during the injection and post-injection periods. However, further experimental research is needed to support this observation. The results of this study indicate that the analyzed formation has a low potential for CO2 sequestration in mineral form and solution over 10,000 years of storage, amounting to 5.50 kg CO2/m3 for reservoir rocks (4.37 kg CO2/m3 in mineral form and 1.13 kg CO2/m3 in dissolved form) and 3.22 kg CO2/m3 for caprock rocks (3.01 kg CO2/m3 in mineral form and 0.21 kg CO2/m3 in dissolved form). These values are lower than in the case of the depleted Brodské oil field, which is a porous reservoir located in the Moravian part of the Vienna Basin. [ABSTRACT FROM AUTHOR]

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Carbonate reservoirs account for 60% of global reserves for oil, making them one of the most important types of sedimentary rock reservoirs for petroleum production. This study aimed to identify key production features that significantly impact oil production rates, enhancing reservoir management and optimizing production strategies. A comprehensive dataset is built from reserves and production history data of 377 onshore carbonate oilfields globally, encompassing features such as production, recovery rate, and recovery degree of the whole lifecycle of an oilfield. XGBoost classifier is trained by K-fold cross-validation and its hyperparameters are optimized by Optuna optimization framework. The results show that XGBoost has the best performance evaluated with metrics including accuracy, precision, recall, and F1 score comparing with decision tree, random forest, and support vector machine. Key production features are identified by analyzing the classification feature importance of XGBoost classifier, including build-up stage cumulative production, plateau stage cumulative production, plateau stage recovery rate, plateau stage recovery degrees, and peak production. In conclusion, oilfield reserve size, build-up stage cumulative production, plateau stage cumulative production, and peak production increase, while plateau stage recovery rate decreases, and the plateau stage recovery degree of small-sized oilfields is slightly greater than that of moderate and large oilfields. The research methodology of this study can serve as a reference for studying production features of other types of oil and gas reservoirs. By applying the methodology to low-permeability oilfields, this paper concludes the key production features that are as follows: low-permeability oilfields generally have lower peak recovery rate, lower plateau stage recovery rate, lower decline stage recovery degree, and lower decline stage recovery rate, along with a wide but generally lower range of decline stage cumulative production compared to conventional oilfields. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]