Search Results (39)

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

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

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

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

The North Caspian Basin, known for its oil and gas potential, was formed because of the evolution of the ancient Tethys Ocean and is also a result of the collision of the East European, Kazakhstania, and Siberian paleocontinents. At the beginning of the Mesozoic Era, it was a part of the northern continental margin of the Neo-Tethys, which formed Eurasia. In the Late Triassic and Early Jurassic, a major restructuring of the North Caspian sedimentary basin occurred, characterized by angular unconformity and the erosion of underlying sediments in the coastal zones of the basin. The sedimentary succession of the depression accumulating in the Mesozoic Era consisted of alternating siliciclastic and carbonate rocks. It began to form due to the destruction of the uplifts formed north and west of the East European craton and Urals, which resulted in coastal clastic material in the Triassic and Jurassic, but by the end of the Jurassic and Cretaceous, when all uplifts existing in the north of Tethys were leveled, it was mostly marine environments that contributed to the accumulation of siliciclastic and carbonate strata. The appearance of a large amount of sedimentary material towards the center of the depression, causing stress, as well as the deflection of the basement, contributed to fault tectonics and the resumption and manifestation of salt tectonics. As a result of the continuous diapirism of salt bodies during the Late Mesozoic, mini basins were formed, in which different sedimentogenesis was manifested. These processes contributed to the redistribution of hydrocarbons from the underlying pre-salt formations to the intermediate depth interval post-salt succession with Permian–Triassic and also near-surface Jurassic–Cretaceous formations. Full article

This study investigates the mineralogy and chemical characteristics of pre-salt clay minerals, classifies them, and defines assemblages in reactive microsites. Using Electron Probe Micro-Analysis (EPMA), the chemical formulas of Mg-rich clays were determined. Stevensite exhibited low interlayer charge and aluminum content, while kerolite was characterized by a minimal charge. K/S (kerolite/stevensite) mixed layer showed intermediate compositions and charges between these endmembers. Saponite was distinguished by higher levels of Al, K, and Fe, along with a higher interlayer charge. The proposed assemblages are as follows: saponite in mudstone facies (without spherulites/shrubs), with a hybrid matrix; pure kerolite in spherulstone and shrubstone facies, marked by the absence of significant reactions and high preservation of matrix and textures; stevensite in facies with extensive matrix replacement by dolomitization/silicification; and K/S and kerolite in similar facies with intermediate matrix replacement levels and the coexistence of two intimately related clay mineral compositions. This study enables reliable differentiation of these species based on point mineral chemistry and mapping, combined with a microsite approach and conventional techniques. Additionally, it discusses the formation of pre-salt clays, influenced by significant kinetic and chemical interactions during their genesis and burial to depths of approximately 5 km. Full article

Orientation tools in borehole imaging logs acquire magnetic information that is currently used for spatial and geographical orientation of the images. We propose to use this magnetic field information to estimate both magnetic susceptibility and remanent magnetization of rocks inside wells. Measurements of these magnetic parameters are not often available in hydrocarbon exploration to support forward modeling of magnetic data, an interpretation tool that has played important role in the exploration risk reduction in the Pre-Salt prospects of Campos Basin, Brazil. The acquired magnetic data requires corrections for tool rotation and diurnal variation of the Earth’s magnetic field before calculation. Then, using a set of simple equations and reasonable assumptions we were able to estimate the magnetic susceptibility of carbonates and basalts, as well as the remanent magnetization of the basalts, from a Pre-Salt well in Campos Basin. When compared to susceptibility values measured in laboratory for the same rock interval, our results show a significant match. This promising result shows the importance of our methodology in providing reliable information that can minimize uncertainties in forward modeling of magnetic data, which contributes to reduction of hydrocarbon exploration risks. Given that direct susceptibility and remanence measurements require oriented samples, a complex and expensive operation in wells, our results offer this rock information without any extra costs since imaging logs are commonly acquired in exploration wells. Besides its use in hydrocarbon exploration, our methodology can be applied to mineral exploration where magnetic susceptibility is an important property for rock identification. Full article

Based on productivity and efficiency indicators, we investigated the performance of the Brazilian oil and gas exploration industry, comparing the performance of this sector with other industrial sectors. We associate productivity with the concept of total factor productivity (TFP), while efficiency is measured using the stochastic frontier production model. Our sample was assembled from the Annual Industrial Survey (PIA) for 29 Brazilian industrial sectors from 2007 to 2019, period of data availability. The results derived from both methods allow us to affirm that the policies resulting from the Pre-Salt have significantly boosted the oil and natural gas extraction sector in terms of technological progress and efficiency. Between 2007 and 2009, the sector was among the least efficient, ranking 29th. However, in 2019 it reached first place in terms of efficiency. This structural change, which began in 2010 as a result of the technological innovations resulting from investments in R&D, has undergone a change since 2010, reflected in the upward trend towards pre-salt exploration promoted by Petrobras, in Rio de Janeiro, Brazil, as well as the new regulatory framework and government incentives for oil exploration in Brazil. Un-fortunately, these productivity gains have not been exported to other branches of industry connected to the oil industry. Full article

Optimizing the drilling process is critical for the exploration of natural resources. However, there are several mechanic parameters that continuously interact with formation properties, hindering the optimization process. Rate of penetration (ROP) and mechanical specific energy (MSE) are considered two key performance indicators that allow the identification of ideal conditions to enhance the drilling process. Thus, the goal of this research was to analyze field data from pre-salt layer operations, using a 2D analysis of parameters as a function of depth, response surface methodology (RSM), and multi-objective optimization. The results show that the RSM method and multi-objective optimization provide better results when compared with 2D analysis of parameters as a function of depth. The RSM method can be used as a tool to analyze the effects of the independent drilling mechanical parameters (WOB, RPM, FLOW, and TOR) on the response variables (ROP and MSE) with a 95% confidence level. Through multi-objective optimization, it was possible to concomitantly achieve an ROP of approximately 22 ft/h and MSE of nearly 11 kpsi using the values of WOB, RPM, FLOW, and TOR of about 11 klb, 109 rev/min, 803 gpm, and 3 klb-ft, respectively. Using high WOB values, i.e., from the mean value up to the maximum value of approximately 43 klb, reflects a low ROP and most likely indicates an operation beyond the foundering point. High FLOW promotes a more efficient hole cleaning and higher rates of cuttings transport, thus preventing eventual in situ drill-bit sticking. Flow adjustment also ensures an adequate balance of dynamic bottom hole pressure, in addition to controlling the force impact force of the drilling fluid in contact with the rock being drilled, expressing importance in terms of efficiency and rock penetration. Finally, it is important to mention that the results of this research are not only applicable to hydrocarbon exploration but also to geothermal and natural hydrogen exploration. Values analyzed and presented with decimal precision should be logically focused as integers when in industrial application. 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