Search Results (29)

The Tajik Basin is located on the eastern edge of the Central Asian segment of the Tethyan tectonic domain. The basin underwent intense tectonic transformation during the Himalayan period, resulting in complex structural styles, unclear original sedimentary characteristics and oil and gas geological conditions, and a complex process of oil and gas accumulation, which restricts the further evaluation of the basin’s exploration potential. Studying the Tajik Basin in the macro background of the Tethys tectonic domain, the tectonic sedimentary evolution of the Tethys tectonic domain has a significant effect on the basin’s tectonic evolution, sedimentary characteristics, and oil and gas accumulation conditions. The Tajik Basin has gone through four stages of tectonic evolution: the Late Permian to Triassic was the stage of back arc foreland basin; the Jurassic period was the stage of back arc extensional faulting depression; the Cretaceous–Paleogene period was the stage of depression basins; and the Neogene is the stage of the regenerated foreland basins. Through field geological surveys and analysis of outcrop samples, it has been determined that the Tajik Basin has developed three sets of source rocks: the Middle and Lower Jurassic, Cretaceous, and Paleogene. Among them, the organic matter abundance of the Middle and Lower Jurassic is relatively high, most of them are in the mature stage, and they are primarily gas-generating source rocks. The Cretaceous and Paleogene source rocks are mainly oil generating and in a low-mature state. There are four sets of reservoirs developed in the Tajik Basin: Middle-Upper Jurassic carbonate rocks, Lower Cretaceous clastic rocks, Upper Cretaceous carbonate rocks and Paleogene carbonate rocks. Comprehensive research shows that the Tajik Basin mainly develops three types of oil and gas reservoirs: Jurassic carbonate gas reservoirs, distributed in the southwestern Gissar Uplift and Surhan Depression in the western part of the basin; Paleogene carbonate reservoirs, distributed in the southern Vakhsh Depression and the eastern Kuliabu Depression; and multi layer–multi lithology oil and gas reservoirs, distributed in the northern Dushanbe Depression. The primary controlling factor for the three types of oil and gas reservoirs is tectonic movement, which forms traps and simultaneously reshapes the reservoirs, ultimately leading to effective accumulation of oil and gas. The distribution of oil and gas in the Tajik Basin is characterized by “west gas and east oil, west more and east less, west pre-salt and east post-salt, and pre-salt gas and post-salt oil”. Affected by the regional tectonic movements of the Tethys rich oil and gas tectonic domain, the basin has high-quality hydrocarbon source rocks, reservoirs, and cap rock conditions. The pre-salt Jurassic has the potential to form large natural gas reservoirs, while the post-salt Cretaceous and Paleogene still have further potential for exploration. Full article

Water management in high-temperature and high-salinity reservoirs remains a critical challenge for oilfield operations, with conventional polymer gel systems exhibiting insufficient thermal stability and salt tolerance under extreme conditions. Here, we establish an integrated computational–experimental platform combining density functional theory (DFT) and molecular dynamics (MD) simulations to rationally design a novel AM/AMPS/AMB (Acrylamide/2-acrylamido-2-methylpropanesulfonic acid/sodium 3-acrylamido-3-methylbutanoate) terpolymer gel plugging agent tailored for the Tahe Oilfield (140 °C, Ca²⁺/Mg²⁺ 10,000 mg L⁻¹). Density functional theory (DFT) calculations of fourteen functional monomers identified AMB as the optimal candidate, achieving further hydrogen bond interactions that stabilize the crosslinked architecture under extreme conditions. This computational pre-screening reduced experimental iterations by over 60% and significantly shortened development cycles compared to conventional trial-and-error approaches. Experimentally, the optimized terpolymer exhibited a 40% increase in storage modulus (150 Pa) relative to AM/AMPS binary systems, 25% improvement in thermal stability (residual carbon at 300 °C), and plugging efficiency exceeding 92% in core flooding tests. Full article

Accurate quantification of mineralogical composition in carbonate rocks is essential for reservoir characterization in the oil industry, directly influencing petrophysical properties such as porosity and permeability. However, traditional methods such as X-ray diffraction (XRD) are destructive and provide limited spatial sampling. The aim of this study was to develop and validate a workflow for the continuous quantification of calcite and dolomite in drill cores from the Brazilian pre-salt oil province by integrating short-wave infrared (SWIR) hyperspectral imaging (HSI) and Machine-Learning algorithms. A total of 80 m of cores were evaluated using 170 XRD-validated samples to calibrate linear, nonlinear, and ensemble models. The results showed that the combination of Multiplicative Scatter Correction (MSC) preprocessing with Multilayer Perceptron (MLP) and Support Vector Regression (SVR) achieved the best performance, reaching an $R^2$ of 0.84. Explainable Artificial Intelligence (SHAP) confirmed the relevance of diagnostic bands between 2330 and 2360 nm, improving geological interpretability of the predictions. The proposed methodology provides a non-destructive and high-resolution alternative for mineralogical profiling, supporting the evaluation of complex reservoirs and decision-making in the oil and gas industry. Although the workflow was validated using a specific pre-salt dataset, future studies should assess its transferability to other carbonate reservoirs and broader geological settings. Full article

Recently, a substantial quantity of oil and gas has been discovered in the pre-salt Lower Cretaceous microbialite successions of Brazil’s Santos Basin, thereby prompting a global surge in research related to microbialites. It has been demonstrated that microbial shoal reservoirs yield the highest hydrocarbon production, with optimal reservoir properties, as evidenced by experience in the field of oilfield production. However, as research progresses, it has become increasingly evident that significant heterogeneity exists in both the lithology and physical properties within microbial shoal bodies. In order to address the identified knowledge gap, the present study employs systematic petrological and petrophysical datasets. These include 30-m continuous core samples, thin-section analyses, routine petrophysical tests and mercury injection capillary pressure (MICP) measurements. The aim is to characterize the internal microfacies architecture and reservoir heterogeneity of microbial shoals. It is imperative to ascertain the principal factors that govern the heterogeneity observed in these reservoirs. This critical step is essential for a comprehensive understanding of the subject matter. The results of the study demonstrate that: the Barra Velha Formation microbial shoals in the Santos Basin can be subdivided into three microfacies, which are delineated from base to top. The foundation of the shoal is the shoal base. The rock composition is dominated by the presence of spherulites, with intracrystalline pores functioning as the primary reservoir spaces. The compositional rocks of the shoal flank are poorly sorted microbial debris, with intergranular and intragranular pores formed by penecontemporaneous dissolution. The sedimentary succession of the shoal core is characterized by well-sorted microbial debris rocks displaying multiple shallowing-upward sequences, with reverse-graded textures. The primary storage space is constituted by fabric-selective pores from penecontemporaneous dissolution, though these are subject to local disruption by destructive silicification. Meanwhile, the microbial shoals demonstrate wide porosity (8.8–26.4%, mean 16.8%) and permeability (0.13–839 mD, mean 169 mD) ranges, thus classifying them as medium-porosity, high-permeability reservoirs. The superimposition of microfacies and diagenetic processes gives rise to considerable reservoir heterogeneity. It is evident that the shoal core microfacies exhibits robust energy and substantial grain size, characteristics that facilitate its exposure above lake level during periods of high-frequency lake-level oscillation. This exposure is further compounded by the influence of atmospheric water dissolution, which remodels the microfacies during the quasi-contemporaneous period. The reservoir quality is optimal, exhibiting the highest proportion of large pores. The reservoir properties of the shoal flank are closely followed by medium and large pores, and those of the shoal base are the worst, with micro and medium pores. Full article

Inorganic scale formation in oil wells is a major flow assurance challenge, causing production losses, increased intervention costs and reduced operational efficiency. In Brazil, recent discoveries in pre-salt reservoirs have increased the relevance of calcium carbonate (CaCO₃) scaling under high-pressure and high-temperature (HPHT) conditions. Experimental data representative of petroleum environments under such conditions, particularly regarding the influence of CO₂ and flow conditions, remain limited. In this study, a compact pressurized experimental unit was designed and constructed to investigate the dynamic formation, deposition and adhesion of CaCO₃ under conditions close to those encountered in oil production systems. A dedicated experimental methodology was developed to promote controlled mixing of aqueous sodium bicarbonate (NaHCO₃) and calcium chloride (CaCl₂) solutions and CO₂ injection, enabling precise control of pressure, temperature and flow regime. The effects of turbulent flow, expressed by different Reynolds numbers, on the deposited CaCO₃ mass and its adhesion to the substrate were systematically evaluated under controlled conditions of 40 °C and a pressure drop of 15 bar was imposed in the control valve in order to promote the flash of CO₂ and CaCO₃ precipitation. Complementary characterization analyses were performed to assess crystal morphology and adhesion detachment strength. The results provide new experimental insights into CaCO₃ scaling mechanisms under CO₂-rich flowing conditions, contributing to improved understanding of scale adhesion and the development of mitigation strategies for flow assurance in oil and gas operations. Full article

Formation damage near the wellbore reduces permeability and limits well productivity, with its effect commonly quantified by the skin factor. This parameter can strongly influence both the technical performance and the economic feasibility of oil recovery projects. In Brazilian pre-salt carbonate reservoirs, acidizing is widely applied, often conducted immediately after well completion. However, the long-term production and economic implications of these treatments remain insufficiently quantified. In this study, synthetic carbonate reservoir models were constructed using porosity and permeability profiles derived from well data representative of pre-salt conditions. Ten models with flow capacities ranging from 3000 to 130,000 mD·m were simulated over 30 years of water injection, considering skin factors from −3 to +20. The results show that wells with flow capacities below 10,000 mD·m exhibited the strongest response to stimulation, achieving up to 35% higher cumulative oil recovery and more than a 100% increase in net present value (NPV) compared with unstimulated cases. For flow capacity values between 10,000 and 40,000 mD·m, production and economic improvements were marginal, with NPV differences typically within 10%. At higher flow capacity (>60,000 mD·m), the stimulation response became negligible, with NPV variations below 0.1%. These findings demonstrate that stimulation effectiveness is primarily governed by reservoir flow capacity. The integrated reservoir–economic evaluation framework developed in this study provides quantitative guidance for optimizing acidizing strategies in carbonate systems representative of deepwater pre-salt environments. Full article

To address the issues of easy degradation, dehydration, and insufficient deep plugging strength of traditional pre-crosslinked gel particles (PPGs) in high-temperature and high-salinity reservoirs, this study innovatively introduced amphiphilic carbon dots (CDs) with both hydrophilic and hydrophobic structures as multifunctional modifiers. The carbon dot-reinforced PPGs (CD-PPGs) were successfully prepared through in situ polymerization. Through systematic characterization, microscopic visualization experiments, and macroscopic oil displacement evaluation, the performance enhancement mechanism and profile control behavior were deeply explored. The results show that the amphiphilic carbon dots significantly enhanced the material’s temperature resistance (up to 110 °C), salt resistance (up to 15 × 10⁴ mg/L salinity), and mechanical properties by constructing a “hydrogen bond-hydrophobic association” dual crosslinking system within the PPG network. More importantly, it was found that CD-PPGs exhibit a unique “self-aggregation” ability in deep reservoirs, which enables the in situ formation of high-strength plugging micelles at the target location while ensuring excellent injectability. At a permeability range of 539.0–2988.6 mD, the sealing rate of 0.5 PV CD-PPGs was greater than 95%. With permeabilities of 490.1 mD and 3020.5 mD under heterogeneous reservoir simulation conditions, the total recovery degree after the CD-PPGs was 52.6%, which was 20.5% higher than that of single water flooding. This study not only developed a high-performance profile control nanomaterial but also elucidated its strengthening mechanism, providing new insights and a theoretical basis for advancing deep profile control technology. Full article

Monitoring bottom-hole pressure (BHP) is critical for reservoir management and flow assurance, especially in offshore fields where challenging conditions and production losses are more impactful. However, reliability issues and high installation costs of Permanent Downhole Gauges (PDGs) often limit access to this vital data. Soft sensors offer a cost-effective and reliable alternative, serving as backups or replacements for physical sensors. This study proposes a novel data-driven methodology for estimating flowing BHP using wellhead and topside measurements from plant monitoring systems. The framework employs ensemble methods combined with clustering techniques to partition datasets, enabling tailored supervised training for diverse production conditions. Aggregating results from sub-models enhances performance, even with simpler machine learning algorithms. We evaluated Linear Regression, Neural Networks, and Gradient Boosting (XGBoost and LightGBM) as base models. A case study of a Brazilian Pre-Salt offshore oilfield, using data from 60 wells across nine platforms, demonstrated the methodology’s effectiveness. Error metrics remained consistently below 2% across varying production conditions and reservoir lifecycle stages, confirming its reliability. This solution provides a practical, economical alternative for studies and monitoring in wells lacking PDG data, improving operational efficiency and supporting reservoir management decisions. Full article

Small reservoirs have important functions, such as water resource guarantee, flood control and drought resistance, biological habitat and maintaining regional economic development. In order to better clarify the impact of agricultural activities on the nutritional status of water bodies in small reservoirs, zooplankton were quantitatively collected from four small reservoirs in the Jiuxianshan agricultural area of Qufu, Shandong Province, in March and October 2023, respectively. The physical and chemical parameters in sampling points were determined simultaneously. Meanwhile, water samples were collected for nutrient salt analysis, and the eutrophication of water bodies in four reservoirs was evaluated using the comprehensive nutrient status index method. The research found that the species richness of zooplankton after farming (100 species) was significantly higher than that before farming (81 species) (p < 0.05). On the contrary, the dominant species of zooplankton after farming (7 species) were significantly fewer than those before farming (11 species). The estimation results of the standing stock of zooplankton indicated that the abundance and biomass of zooplankton after farming (92.72 ind./L, 0.13 mg/L) were significantly higher than those before farming (32.51 ind./L, 0.40 mg/L) (p < 0.05). Community similarity analysis based on zooplankton abundance (ANOSIM) indicated that there were significant differences in zooplankton communities before and after farming (R = 0.329, p = 0.001). The results of multi-dimensional non-metric sorting (NMDS) showed that the communities of zooplankton could be clearly divided into two: pre-farming communities and after farming communities. The Monte Carlo test results are as follows (p < 0.05). Transparency (Trans), pH, permanganate index (COD_Mn), electrical conductivity (Cond) and chlorophyll a (Chl-a) had significant effects on the community structure of zooplankton before farming. Total nitrogen (TN), total phosphorus (TP) and electrical conductivity (Cond) had significant effects on the community structure of zooplankton after farming. The co-linearity network analysis based on zooplankton abundance showed that the zooplankton community before farming was more stable than that after farming. The water evaluation results based on the comprehensive nutritional status index method indicated that the water conditions of the reservoirs before farming were mostly in a mild eutrophic state, while the water conditions of the reservoirs after farming were all in a moderate eutrophic state. The results show that the nutritional status of small reservoirs in agricultural areas is significantly affected by agricultural activities. The zooplankton communities in small reservoirs underwent significant changes driven by alterations in the reservoir water environment and nutritional status. Based on the main results of this study, we suggested that the use of fertilizers and pesticides should be appropriately reduced in future agricultural activities. In order to better protect the water quality and aquatic ecology of the water reservoirs in the agricultural area. Full article

Understanding tortuosity is essential for accurately modeling fluid flow in complex porous media, particularly in the sub-surface reservoir rock; therefore, tortuosity estimation was evaluated using three approaches: Streamline streamline simulations via the Lattice Boltzmann Method (LBM), geometric pathfinding using Dijkstra’s algorithm, and empirical modeling based on pore-structure parameters. The analysis encompassed 1963 micro-Computed Tomography (micro-CT) images of Brazilian pre-salt carbonate and sandstone samples, with the effective porosity extracted from LBM velocity fields, isolating flow-contributing pores, establishing streamline tortuosity as the reference standard. Sandstones exhibited relatively narrow tortuosity ranges (Dijkstra: 1.29–1.75; Streamline: 1.18–2.61; Empirical: 1.18–4.42), whereas carbonates display greater heterogeneity (Dijkstra: 1.00–3.18; Streamline: 1.00–3.68; Empirical: 1.59–4.93). Model performance assessed using the corrected Akaike Information Criterion (AICc) revealed that the best agreement with the data was achieved by the semi-empirical model incorporating coordination number and minimum throat length (AICc = −113.11), followed by the Dijkstra-based geometrical approach (−99.74) and the empirical porosity-based model (202.23). There was a nonlinear inverse correlation between tortuosity and effective porosity across lithologies. This comprehensive comparison underscores the importance of incorporating multiple pore-scale parameters for robust tortuosity prediction, improving the understanding of flow behavior in heterogeneous reservoir rocks. Full article

The Lower Congo Basin (LCB) is a rift-type basin with petroleum systems that developed at the western African margin in association with the opening of the South Atlantic. Two pre-salt siliciclastic units of the LCB, Lucula (uppermost Jurassic to Lower Cretaceous) and Chela (Aptian) formations, were sampled in deep wells and outcrops. Heavy mineral assemblages, XRD mineralogy and geochemistry indicate prevailing source in high rank metamorphic rocks from western regions of the Lower Congo Belt. However, sediment composition reveals some provenance heterogeneity. For the Chela Formation, occasionally abundant amphibole in the heavy mineral fraction, coupled with relatively high Fe and Ti proportions, suggest that it formed when deeper crustal units were exhumed. The Lucula Formation collected in outcrops have composition substantially different from Lucula and Chela samples collected in deep wells, indicating distinct provenance and the incorporation of recycled material. A significant diagenetic overprint compromises the interpretation of compositional features in terms of paleoclimate. The presence of a chemical component with dolomite, halite and diverse sulphates and the stratigraphic position of the Chela Formation at the transition to a thick evaporitic succession are compelling evidence of deposition under warm and dry conditions, which are probably more extreme than those associated with the original stages of rifting recorded by the Lucula Formation. Full article

The complex interaction of hydrothermal fluids and carbonate rocks is recognized to promote significant impacts on petroleum systems, reservoir porosity, and potential. The objective of this study is to investigate the fluid phases entrapped in the mineral phases of the Barra Velha Formation (Santos Basin), including their petrographic paragenetic relationships, relative timing, temperatures of migration events, and maximum temperature reached by the sedimentary section. The petrographic descriptions (387), Rock-Eval pyrolysis (107), fluid inclusion petrography (14), and microthermometry (428) were performed on core and sidewall samples from two wells from one field of the Santos Basin. Hydrocarbon source intervals were primarily identified in lithologies with high argillaceous content. Chert samples still retain some organic remnants indicative of their original composition prior to extensive silicification. Redeposited intraclastic rocks exhibit the lowest organic content and oil potential. A hydrothermal petroleum system is identified by fluids consisting in gas condensate, light to heavy undersaturated oil, occasionally accompanied by aqueous fluids influenced by juvenile and evaporitic sources, and localized flash vaporization events. These hydrothermal fluids promoted silicification and dolomitization, intense brecciation, and lead to enhanced porosity in different compartments of the reservoir. The relative ordering of paleo-hydrothermal oils and the main oil migration and accumulation events has improved our understanding of the petroleum systems in the basin. This contribution is significant for future regional research on the evolution of fluid systems and their implications for carbonate reservoirs. Full article

In this study, we used machine learning (ML) to estimate time-lapse velocity variations in a reservoir region using seismic data. To accomplish this task, we needed an adequate training set that could map seismic data to velocity perturbation. We generated a synthetic seismic database by simulating reservoirs of varying velocities using a 2D velocity model typical of the Brazilian pre-salt ocean bottom node (OBN) acquisition, located in the Santos basin, Brazil. The largest velocity change in the injector well was around 3% of the empirical velocity model, which mimicked a realistic scenario. The acquisition geometry was formed by the geometry of 1 shot and 49 receivers. For each synthetic reservoir, the corresponding seismic data were obtained by estimating a one-shot forward-wave propagation using acoustic approximation. We studied the reservoir illumination to optimize the input data of the ML inversion. We split the set of synthetic reservoirs into two subsets: training (80%) and testing (20%) sets. We point out that the ML inversion was restricted to the reservoir zone, which means that it was inversion-oriented to a target. We obtained a good similarity between true and ML-inverted reservoir anomalies. The similarity diminished for a situation with non-repeatability noise. Full article

The complexity of petroleum phases in deep formations plays an important role in the evaluation of hydrocarbon resources. Pressure is considered to have a positive impact on the preservation of liquid oils, yet direct evidence for this phenomenon is lacking in the case of deep reservoirs due to late destruction. Here, we present fluid-inclusion assemblages from a deep reservoir in the Tazhong area of the Tarim Basin, northwestern China, which formed as a direct consequence of fluid pressure evolution. Based on thermodynamic measurements and simulations of the coexisting aqueous and petroleum inclusions in these assemblages, the history of petroleum activities was reconstructed. Our results show that all analyzed fluid-inclusion assemblages demonstrated variable pressure conditions in different charging stages, ranging from hydrostatic to overpressure (a pressure coefficient of up to 1.49). Sequential petroleum charging and partial oil cracking may have been the main contributors to overpressure. By comparing the phases of petroleum and fluid pressures in the two wells, ZS1 and ZS5, it can be inferred that overpressure inhibits oil cracking. Thus, overpressure exerts an important influence on the preservation of liquid hydrocarbon under high temperatures. Furthermore, our results reveal that the exploration potential for liquid petroleum is considerable in the deep reservoirs of the Tarim Basin. Full article

Drill-bit metamorphism (DBM) is the process of thermal degradation of drilling fluid at the interface of the bit and rock due to the overheating of the bit. The heat generated by the drill when drilling into a rock formation promotes the generation of artificial hydrocarbon and non-hydrocarbon gas, changing the composition of the gas. The objective of this work is to recognize and evaluate artificial gases originating from DBM in wells targeting oil accumulations in pre-salt carbonates in the Santos Basin, Brazil. For the evaluation, chromatographic data from advanced mud gas equipment, drilling parameters, drill type, and lithology were used. The molar concentrations of gases and gas ratios (especially ethene/ethene+ethane and dryness) were analyzed, which identified the occurrence of DBM. DBM is most severe when wells penetrate igneous and carbonate rocks with diamond-impregnated drill bits. The rate of penetration, weight on bit, and rotation per minute were evaluated together with gas data but did not present good correlations to assist in identifying DBM. The depth intervals over which artificial gases formed during DBM are recognized should not be used to infer pay zones or predict the composition and properties of reservoir fluids because the gas composition is completely changed. Full article