Hydrocarbon Reservoirs Research Articles

FEATURES OF THE LITHOLOGICAL STRUCTURE AND DEVELOPMENT OF RESERVOIR ROCKS AND HYDROCARBON RESERVOIRS IN THE MIDDLE DEVONIAN SEDIMENTS OF THE SOUTHERN PART OF THE TUZLIV DEPRESSION (DOBRUDJA FOREDEEP)

The aim of the work was to clarify the features of the lithological structure of the Middle Devonian sediments of the Zhovtoyarska-Tuzlivska and Biloliska-Zarichnenska prospective areas of the Dobrudja Foredeep and to determine its influence on the formation of reservoir rocks, traps and hydrocarbon reservoirs. The research was based on the results of geophysical research of wells (radioactive methods) in combination with fragmentary geological (lithological) data. As a result, 9 lithocycles of regressive nature were identified in the section for the first time (e-1 – e-5; g-1 – g-4). Each lithocycle is characterized by a two-membered structure and represents a separate productive horizon (PH). The lower parts of the latter are composed of porous and fractured reservoir rocks (limestones, dolomites, siltstones, sandstones), and the upper parts are composed of fluid-resistant packs (marls, anhydrites). It has been shown that cyclites are grouped into larger units (mesocyclites) of re- or progressive nature, which in different wells (in separate intervals) exhibit a certain similarity or difference in structure. Such spatial and age variability is caused, on the one hand, by the placement of wells in different facies zones of the sulfate-carbonate shelf, and on the other, by the processes of interaction of synsedimentary tectonic movements and paleoceanographic (sea level changes, etc.) factors. The consequence of this is the lateral lithological heterogeneity, which in the petrogeological aspect is manifested in the morphological features of the reservoirs and the character of the development of various types of reservoirs and ultimately determines, taking into account secondary rock changes, the prospects of specific productive horizons. Thus, for the Zhovtoyarska-Tuzlivska area, the vaulted trap is localized near borehole Zhovtoyarska-1 (e-1, e-2 productive horizons), according to other horizons it is fixed near borehole Zhovtoyarska-2. The development of lithological traps is predicted in e-1, e-3 and e-4 productive horizons, which is associated with the wedging of pore reservoirs in the direction from borehole Tuzlivska-2 to borehole Zhovtoyarska -2 and -1. For most productive horizons, the quality of reservoir rocks is expected to deteriorate in the same direction, which suggests the possibility of catagenetic screening of fluids. For the Biloliska-Zarichnenska area, along all productive horizons, trap vaults are localized near borehole Zarichnenska-1 or further south. The most capacious are the traps of horizons e-1, e-4 and e-5, composed mainly of pore-type collectors, the quality of which is low due to anhydritization. The best reservoir rocks are predicted in the Givetian sediments (g-2 – g-4 productive horizons) of borehole Zarichnenska -1.

A Method for Predicting the Action Sites of Regional Mudstone Cap Rock Affecting the Diversion of Hydrocarbons Transported along Oil Source Faults

Regional mudstone cap rock has an important influence on the oil and gas distribution of the oil source faults below it. Therefore, studying the influence of these mudstone cap rocks on the hydrocarbon distribution pattern is fundamental to understanding the oil and gas distribution of the lower generation and upper reservoir reservoirs in the Bohai Bay Basin. This study classified two types of hydrocarbon diversion from oil source faults: blockage diversion and seepage diversion. To locate them, we established a method to predict the areas with blockage diversion and seepage diversion separately by superimposing the sealing and leakage parts of the regional mudstone cap rock with the regions of the connected distribution of sand bodies and the favorable hydrocarbon transport sites of the oil source faults, respectively. We used this approach to predict the locations where hydrocarbons are diverted by the oil source faults under the regional mudstone cap rocks in the first and second sections of the Dongying Formation (E3d1-2) in the Liuchu area of the Raoyang Sag, Bohai Bay Basin. The results show that the regional mudstone cap rock’s blockage diversion occurs mainly in the south-central area of Liuchu, with a localized distribution in the northern part. The seepage diversion site is primarily located in the northeastern area and is also found locally in the west. Both diversions are beneficial for the accumulation of hydrocarbons from the source rocks of the first member of the Shahejie Formation (E3s1) to the upper second member of the Dongying Formation (E3d2U). The latter can also accumulate hydrocarbons in the Guantao Formation (N1g). The results align with the hydrocarbon distribution, demonstrating the feasibility of our method to predict various oil source fault diversion sites under the regional mudstone cap rock. This prediction method offers valuable guidance for exploring the lower generation and upper reservoir hydrocarbon accumulations in hydrocarbon-bearing basins.

Using iron speciation to track hydrocarbon migration in bleached rocks and its implications for reservoir reconstruction

Bleaching of red rock beds by hydrocarbons can provide valuable insights for hydrocarbon migration and reservoir transformation. This study investigated the bleaching effects of hydrocarbons on various rock types in the Dushanzi mud volcanic area. Bedrock and bleached samples of different lithologies, including mudstone, sandy mudstone and sandstone, were systematically collected and analyzed for their iron species, mineralogical and chemical compositions using Mössbauer spectroscopy, X-ray diffraction and X-ray fluorescence, respectively. The results indicate that the iron species of the studied samples were dominated by para-Fe3+ (from 44% to 76%), with variable contents of mag-Fe3+, para-Fe2+ and pyr-Fe2+. When compared to the related unbleached rocks, the bleached rocks exhibited a higher proportion of reduced Fe (para-Fe2+ and pyr-Fe2+). The pyr-Fe2+ in the sandstones and sandy mudstones was significantly higher than that of the mudstone interlayers. The observed variations in iron species were consistent with changes in mineralogical and chemical compositions, which can be correlated with the petrological properties of rocks. The increase of quartz and decrease of feldspar and carbonates in the bleached rocks could be attributed to the dissolution of feldspar and the subsequent secondary enlargement of quartz. Geofluids containing crude oils and natural gases preferentially dissolved K-feldspar over albite. The bleached rocks had a significant decrease in the proportion of kaolinite and a slight decrease in the proportion of chlorite, while the proportions of smectite and illite were increased. The dissolution of K-feldspar could provide sufficient K+ for the formation of illite, and the appearance of smectite in the bleached samples might be related to the dissolution of albite in an alkaline environment. The dissolution of carbonates and feldspar, along with the transformation of clay minerals, had a notable positive effect on the formation of secondary porosity, facilitating hydrocarbon migration. These findings provide valuable insights into the interactions between hydrocarbons and different lithologies, informing the impact of hydrocarbon migration on reservoir reconstruction in similar geological settings.

New and Highly Accurate Static Young's Modulus Model Using Machine Learning Techniques.

Static Young's modulus (E s) is a critical property required in numerous petroleum calculations. Various models to forecast E s have been proposed in the literature. However, existing models, by and large, lack precision and are confined to specific data set ranges. This study proposes an alternative approach for E s determination, utilizing different machine learning methods, such as an adaptive neuro-fuzzy inference system (ANFIS). In these proposed methods, the predictor variables include bulk formation density (RHOB), shear wave velocity (DTs), and compressional wave velocity (DTc). The models were trained on a data set comprising 1853 hydrocarbon reservoir rock samples from globally diverse locations. They were evaluated using trend, group error, and statistical error analyses. To test the efficacy of the proposed models, the optimally performing model was identified and used to detect the rock types along with the previously published models. Results indicated that ANFIS is the optimum model and can predict E s with an average absolute percentage relative error (AAPRE) of 5.1% and a correlation coefficient (R) of 0.9602. The ANFIS method has some benefits over other machine learning approaches insofar as its superiority in reaching a quicker decision about the mapped relationship between the inputs and outputs because it combines artificial neural networks and fuzzy logic in one tool. The ANFIS can perform a highly nonlinear mapping and displays a better learning ability. The proposed ANFIS model demonstrates its ability to capture accurate physical relationships between input rock properties and E s through trend analysis, which shows that increasing the RHOB increases the E s. Contrarily, increasing the DTc and DTs reduces the E s. Furthermore, the ANFIS model can accurately detect the rock types based on its E s determinations. This research demonstrates the importance of accurately predicting E s for the proper identification of rock types. Thus, this study offers potential advancements in geological assessments of hydrocarbon reservoirs and improvements in many petroleum engineering applications.

Effective application of geological process modeling for unravelling carbonate build-up complexity: A case study from the EX-Carbonate build-up in central Luconia Province, Malaysia

In the dynamic field of carbonate reservoir Exploration, the need for specialized models is vital, assisting as a key tool to facilitate interdisciplinary collaboration and enhance strategies for predicting reservoir behavior. This study examines the use of geological process (GPM), a standard tool to simulate forward stratigraphic modelling, particularly focusing on the Central Luconia Province in the South China Sea. Central Luconia Province stands out for its extensive carbonate build-ups and is recognized as a prolific hydrocarbon reservoir. Forward Stratigraphic Modelling (FSM) leads to a paradigmatic change in geological modeling. Unlike geostatistical models controlled by geometrical parameters, FSM relies on mathematical representations of the physical rules determining erosion, transport, and sedimentation in carbonate growth. This tool, supported by various researchers, has proven its ability in quantitative sedimentary system analysis across diverse temporal and spatial scales. This study located in EX Field showcases the ability of stratigraphic forward modeling in replicating sedimentary complexities and resulting stratigraphic architecture of the EX isolated carbonate platform. The methodology links parameters from existing literature with multiscale data. Additionally, carbonate production laws, contingent on water depth, play a pivotal role in the meticulous modeling process. This work illustrates the efficacy of geological process modelling as a transformative approach for unraveling the complexities of carbonate systems, particularly in regions with prolific hydrocarbon reservoirs like Central Luconia. The incorporation of literature-derived parameters and multiscale data serves as evidence of the model's ability to offer nuanced understandings of the dynamic evolution of carbonate platforms, thereby advancing our understanding of reservoir prediction and future management strategies.

Shale Oil Generation Conditions and Exploration Prospects of the Cretaceous Nenjiang Formation in the Changling Depression, Songliao Basin, China

Low-maturity shale oil predominates in shale oil resources. China’s onshore shale oil, particularly the Cretaceous Nenjiang Formation in the Songliao Basin, holds significant potential for low-maturity shale oil, presenting promising exploration and development prospects. This study delves into the hydrocarbon generation conditions, reservoir characteristics, and oil-bearing property analysis of the mud shale from the Nen-1 and Nen-2 sub-formations of the Nenjiang Formation to pinpoint favorable intervals for shale oil exploration. Through the integration of lithology, pressure, and fracture distribution data in the study area, favorable zones were delineated. The Nen-1 sub-formation is widely distributed in the Changling Depression, with mud shale thickness ranging from 30 to 100 m and a total organic content exceeding 2.0%. Type I kerogen predominated as the source rock, while some samples contained type II kerogen. Organic microcomponents primarily comprised algal bodies, with vitrinite reflectance (Ro) ranging from 0.5% to 0.8%. Compared to Nen-1 shale, Nen-2 shale exhibited less total organic content, kerogen type, and thermal evolution degree, albeit both are conducive to low-maturity shale oil generation. The Nen-1 and Nen-2 sub-formations predominantly consist of clay, quartz, feldspar, calcite, and pyrite minerals, with minor dolomite, siderite, and anhydrite. Hydrocarbons primarily reside in microfractures and micropores, including interlayer micropores, organic matter micropores, intra-cuticle micropores, and intercrystalline microporosity, with interlayer and intra-cuticle micropores being dominant. The free oil content (S1) in Nen-1 shale ranged from 0.01 mg/g to 5.04 mg/g (average: 1.13 mg/g), while in Nen-2 shale, it ranged from 0.01 mg/g to 3.28 mg/g (average: 0.75 mg/g). The Nen-1 and Nen-2 sub-formations are identified as potential intervals for shale oil exploration. Considering total organic content, oil saturation, vitrinite reflectance, and shale formation thickness in the study area, the favorable zone for low-maturity shale oil generation is primarily situated in the Heidimiao Sub-Depression and its vicinity. The Nen-2 shale-oil-enriched zone is concentrated in the northwest part of the Heidimiao Sub-Depression, while the Nen-1 shale-oil-enriched zone lies in the northeast part.

Astronomical timescale across the middle Permian–Early Triassic unconformities in the northwestern Junggar Basin: Implications for the origin of the unconformities

The middle Permian–Early Triassic terrestrial successions in the Junggar Basin record an important tectonic transformation stage characterized by the development of unconformities. These unconformities control billion-ton-scale hydrocarbon reservoirs in the northwestern Junggar Basin; however, their age, duration and underlying causes remain uncertain in the absence of an accurate Permian‒Triassic timescale. This study performed a comprehensive cyclostratigraphic analysis utilizing natural gamma ray data from 14 wells to determine the age and duration of the unconformities spanning from the middle Permian Lower Wuerhe (P2w) Formation to the lower Triassic Baikouquan (T1b) Formation while also revealing their potential origins. Our results suggest that astronomically forced climate changes were recorded in the western Junggar Basin during the Permian‒Triassic period. By applying astronomical tuning through sedimentation rates across each well, 14 time-domain series were generated. Using two previously reported maximum sedimentary ages from detrital zircon U–Pb dating, a 38.2-million-year long astronomical timescale was constructed, encompassing the period from the middle Permian Xiazijie Formation to the lower Triassic Baikouquan Formation. This analysis constrains the duration of unconformities between the P2w and T1b formations to ∼7–23 Myr. By integrating the duration, order, and implications of these unconformities with previously reported evidence, we conclude that the unconformity between the middle Permian and upper Permian was driven primarily by tectonic inversion resulting from intensified regional tectonic activity. In contrast, the unconformity between the upper Permian and Lower Triassic likely arose from uplift and erosion induced by compressive stresses associated with tectonic activity, which contributed to the formation of unconformities and stratigraphic discontinuities. This work provides a crucial reference for further studies aimed at integrating detailed sedimentological analyses with high-resolution geochronological data to further elucidate the timing and effects of these tectonic events on sedimentary facies and basin development.

Diagenetic and hydrothermal events revealed by an Ediacaran dolomite breccia from the Araras-Alto Paraguai basin, southern Amazon Craton

The establishment of extensive carbonate platforms characterized the Ediacaran period during CaCO3 oversaturation events and the exceptional creation of accommodation space associated with the aftermath of the Marinoan glaciation (∼635 Ma). Carbonate deposits in the Araras Group record the early Ediacaran period, stage 1, in the Amazon Craton. The Serra do Quilombo Formation is an intermediate unit characterized by heavily fractured and faulted dolomites, as well as the presence of dolomite-cemented breccias (CB) overlying thick limestone packages associated with diagenetic and hydrothermal modifications. These features are commonly attributed to structurally controlled hydrothermal dolomitization (HTD) and are of significant economic importance as hydrocarbon reservoirs and Mississippi Valley-type (MVT) lead-zinc mineralization hosts. This study aims to unravel the origin of cemented breccias and the diagenetic/burial processes within the unit, focusing on dolomitization processes. Dolomite samples were analyzed using petrographic, scanning electron microscopy, microprobe, micro-Raman, cathodoluminescence, and isotopic analyses (δ13C, δ18O, 87Sr/86Sr) to unravel their burial history. CBs are sub-vertical to sub-horizontal bodies with complex geometries, generally cutting bedding at high angles, indicating hydrofracturing processes related to vertical flows of hydrothermal fluids (hydraulic breccia) and present the typical cockade texture of expansion breccias in dilatational faults. The substitutive matrix RD1 is the main constituent of the Serra Quilombo Formation, its low correlation between δ13C and δ18O (R2 = 0.009), the well-preserved fabric, and the similarity with the isotopic values (C and Sr) documented for Ediacaran carbonates, suggest that the syndepositional dolomitization. The first generation of dolomite cement (DC1) and the last phase of dolomitic cementation (saddle dolomite - SD) occur, filling pores, CBs, and fractures. The cockade texture of the breccias evidences a low precipitation rate or a pause in precipitation between DC1 and SD. Concurrently, DC1 has isotopic signals of δ18O = −4.34 ± 1.32‰ (n = 18) and 87Sr/86Sr = 0.708831 (n = 2), while SD has values of δ18O = −9.57 ± 2.51‰ (n = 15) and 87Sr/86Sr = 0.711464 (n = 3). The large isotopic fractionation between DC1 and SD suggests different dolomitizing fluids. This relationship shows an increase in 87Sr in the fluid as the temperature increases; moreover, the enrichment in 87Sr of the fluid is explained by the interaction of this fluid with rocks from the crystalline basement. Thus, the main conduit for the ascent of this radiogenic fluid would be faults with deep roots spatially close to tectonically active zones. Lastly, the presence of tectonic stylolites cutting cemented breccias and rotated zebra-like strata-bound structures suggests that brecciation occurred before the installation of fragile post-Ordovician transtensional structures, preceding the establishment of Paleozoic Basins on the South American Platform.

Seismic Facies-Controlled Porosity Prediction in a Tight Sandstone Reservoir Based on the XGBoost Algorithm

Porosity is one of the most important properties for evaluating hydrocarbon reservoirs. There is a strong nonlinearity between seismic data and rock physical properties. Machine learning methods possess the powerful ability to capture complex nonlinear relationships between these two parameters, holding significant potential for porosity prediction in tight sandstone reservoirs. In this study, we propose a seismic facies-controlled porosity prediction method based on the extreme gradient boosting algorithm. Through seismic meme inversion method,we obtain high-resolution P-impedance data. In the inversion process, lateral variations of seismic waveforms were utilized instead of the variogram function. We create labels for model training using porosity curves and borehole side P-impedance data, applying them to the extreme gradient boosting regressor. To demonstrate its feasibility, we apply the model to a real 3D case from an oil field in the Songliao Basin. Our application results demonstrate that this method can provide porosity predictions for tight sandstone reservoirs, maintaining consistency with seismic waveforms and adhering to seismic facies control patterns. The method uses only acoustic travel time, density, gamma rays, and spontaneous potential well-log data and post-stack 3D seismic data as inputs, allowing for quick porosity predictions in the field. Compared to the seismic facies-controlled inversion combined with support vector machine and multi-Layer perceptron methods, the method proposed in this study provides more reliable porosity predictions, offering insights and references for the exploration and development of tight sandstone reservoirs.

Reservoir oriented migrated seismic image improvement and poststack seismic inversion using well-seismic mistie

In seismic exploration of subsurface hydrocarbon reservoirs, migrated seismic image is the foundation for structural interpretation and subsequent seismic inversion for reservoir properties. Seismic events in migrated images can be mispositioned due to several factors including seismic velocity inaccuracy. The mispositioned events lead to poor well-seismic tie and degrades the accuracy of subsequent inversion and reservoir prediction. Particularly, the mistie can be quite obvious for the mid- and mature- phases of the reservoir development after many wells drilled. We propose to utilize the information from mistie between seismic images and synthetic traces to improve the accuracy of migrated seismic images and thus inversion results. Our method includes three major steps: firstly, calculate time shifts between the synthetic traces and the co-located seismic trace using the path-limited dynamic time warping (PDTW) algorithm; then compute the time shift volume for the entire migrated image using the seismic-driven modeling approach based on the time shift traces at the well locations; apply the time shift volume to update the migrated image. The improved seismic volume can be used for further processing such as seismic inversion, which makes the inversion results more consistent with seismic and well data. We apply our method to synthetic and field datasets. The results demonstrate that the updated seismic image has an improved seismic well tie and an improved inversion result. Our method indicates a venue for a better honor of seismic and well data in reservoir characterization.

Interplay and feedback between tectonic regime, faulting, sealing horizons, and fluid flow in a hydrocarbon-hosting extensional basin: The Val d'Agri Basin case, Southern Italy

Understanding the factors that govern past fluid circulation in tectonically active and/or hydrocarbon-rich basins is crucial for elucidating present-day fluid-flow scenarios. We investigate the circulation of paleo-fluids in the extensional-transtensional Val d'Agri Basin (southern Italy), home to a giant oil field and significantly affected by both natural and human-induced seismicity. Our aim is to understand how faulting and the variable thickness of the clay-rich tectonic mélange, which constitutes the seal of the hydrocarbon reservoir, influenced past fluid flow under different tectonic regimes. To achieve this, we combined multiscale structural observations with isotope (C, O, clumped, and Sr) and Rare Earth and Yttrium (REY) analyses of fault-related calcite mineralizations. Using analytical methodologies that allow the analysis of sub-milligram samples for carbonate clumped isotopes, we provided a detailed characterization of the variability in precipitation temperatures and composition of parental fluids in both space and time. Our results reveal five main types of parental fluids, ranging from meteoric to intraformational and deep crustal, which were differently involved in the tectonic evolution of the Val d'Agri Basin. During orogenic shortening, vertical fluid circulation was mostly limited and compartmentalized, whereas post-orogenic extensional faulting promoted the ascent of deep fluids. Our findings indicate that the sealing properties of the mélange were likely enhanced locally by increased thickness but were also compromised by fault activity and associated seismic events. Fluid circulation in the study area has been influenced by the prevailing tectonic regime (compressive vs. extensional), stratigraphic-structural architecture, properties of impermeable horizons, and seismic events. The model proposed for the Val d'Agri Basin elucidates past processes that are useful for understanding current fluid circulation in the basin itself and can be applied to other basins where fluid circulation is partly manipulated by human activities.

Volcanic weathered crust reservoir analog: Insights from fault-controlled fracture permeability in the trachytic rocks of the Pernambuco Basin, NE Brazil

Naturally fractured volcanic rocks represent a globally significant potential hydrocarbon reservoirs and can also be used for CO2 storage; however, the study of volcanic reservoirs in Brazil is limited. Although numerous volcanic reservoir types have been classified, relatively few studies are dedicated to the weathering of crust-like reservoirs, i.e., volcanic rocks undergoing subaerially alteration by weathering prior to deep burial. This study aims to characterize a volcanic weathered crust reservoir analog located in the coastal zone of the Pernambuco Basin, NE Brazil. We applied a multiscale approach motivated by the expressive potential of volcanic rocks as reservoirs in this marginal basin and considered their implications for CO2 geological storage projects. The deformational aspects observed in this analog have also been observed in other volcanic rocks that crop out in the coastal zone, thus, the data provided here can guide future characterization of both onshore and offshore reservoirs. We focused on an 80 m wide outcrop and employed geometric and topological analysis of two-dimensional fracture networks to investigate the influence of regional fault zone control on the fracture permeability tensors. The parameters of fracture systems were studied using terrestrial gravimetric data, orthophoto mosaic obtained by an unmanned aerial vehicle (UAV), petrography, and outcrop-based structural data. The investigated outcrop includes porphyritic trachytes with euhedral sanidine crystals and minor quartz phenocrysts, sourced from the Ipojuca Magmatic Suite. The residual Bouguer map indicates the influence of at least two regional rift fault zones, i.e., NW-SE (strike-slip) and NE-SW (normal) trending systems, in the studied rocks. These trachytic rocks exhibited a marked dissolution of sanidine phenocrysts and matrix, columnar disjunctions, and natural fractures, causing the porosity and permeability of the reservoir analog to increase. Geometric and topological analyses showed that the south-central sector of the outcrop exhibits heightened connectivity within the fracture network. Furthermore, the principal fracture permeability is controlled by the primary families of the fracture network and regional fault zones. Our results demonstrate that the fracture network observed in the volcanic reservoir analog was influenced by the post-rift tectonic reactivation of Cretaceous structures within the Pernambuco Basin. The secondary porosity resulting from weathering and subsequent dissolution of the primary constituents and fractures of the rocks studied demonstrates the potential for the exploration of these reservoirs as models for known occurrences of volcanic rocks in the onshore and offshore domains of the Pernambuco Basin.

Deformation and fluid flow history of a fractured basement hydrocarbon reservoir below the Sab'atayn Basin, Habban Field, Yemen

Fractured crystalline basement reservoirs are of increasing economic interest for oil and gas exploration and subsurface fluid storage. The successful characterization of these reservoirs is commonly challenged by their structural heterogeneity, complexity in fracture distribution and flow properties at multiple scales, and the difficulty of imaging fractures in exploration seismic. We analyzed the fracture geometry and fracture diagenetic attributes in two oriented cores from the Habban Field in the Late Jurassic Sab'atayn Basin (Yemen) to evaluate the multi-phase deformation history and fracture flow pathway evolution for (hydrothermal) fluids and hydrocarbons. Analyses included petrographic and fluid inclusion analysis of fracture-filling cements, and stable sulfur isotope analyses of fracture-filling pyrite.The Paleoproterozoic basement consists of amphibolite-facies metamorphic ortho- and paragneiss cut by several phases of Neoproterozoic granitoid intrusions. The investigated lithologies in the drill cores comprise (1) epidote quartzite, (2) amphibolite, (3) monzogranite, (4) meta-arkose, and (5) quartz-feldspar porphyry. These lithologies show an inhomogeneous fracture network that is partially cemented. Ediacaran brittle-ductile deformation (D1) recognized only within a Pan-African monzogranite lead to cataclasis and porosity generating alteration. Late Jurassic – Early Cretaceous extension (D2) related to the break-up of Gondwanaland and the formation of the Sab'atayn Basin is found in all lithologies and likely resulted in pervasive quartz cementation. Late Jurassic fractures parallel to the NW-SE trending long axis of the Sab'atayn Basin are best recognized in a strongly foliated amphibolites. Cenozoic extensional fracturing (D3) reactivated older structures, which probably formed during activity of the Neoproterozoic Najd Fault System and caused multi-phased (pyrite-(saddle) dolomite-calcite) fracture cementations. The sulfur isotope compositions of pyrite with δ34S values ranging between −17.4 and + 26.4‰ vs. V-CDT reflects the variability of the fluid source during sulphide mineral formation from hydrocarbon-rich hydrothermal solutions. Fluid inclusions indicate that cementation reactions occurred in a relatively narrow temperature field between 120 °C and 140 °C, ideal for hydrocarbon maturation. Our results demonstrate the potentially complex charge history of basement reservoirs, involving multiple phases of fracture formation and cementation, and fluid charge episodes.

An improved prediction model for miscibility characterization and optimization of CO2 and associated gas co-injection

Insufficient reservoir pressure and gas source problems seriously limit effective applications of CO2 flooding in hydrocarbon reservoirs. An attractive strategy is to co-inject the produced associated hydrocarbon gas with CO2 to achieve miscible/near-miscible flooding to enhance oil recovery. However, the composition of the injected mixture and the in-situ spatio-temporal composition evolution of the displacing/displaced fluids significantly affect the CO2-oil miscibility and the overall hydrocarbon recovery performance. In this work, based on slim tube simulation results, a prediction model of minimum miscible pressure (MMP)/minimum near-miscible pressure (MNMP) is established. This model takes into account the effects of CO2 concentration distribution, oil composition and temperature changes to achieve accurate spatiotemporal characterization of miscibility in the reservoir. In addition, the distribution law of the phase and components front for the impure CO2 injection process was also investigated. The miscible volume factor and recovery efficiency were used as the basis for judging the minimum injection concentration limit of CO2. The simulation results of slim tube experiment indicate that the MMP and MNMP obtained are 16.74 MPa and 12.35 MPa, respectively. Furthermore, the error caused by the traditional slim tube experiment can be reduced by using the CO2 produced fraction. It is found that CO2 injection concentration and reservoir temperature are the main factors affecting miscibility, but injection rate has less effect. Moreover, the fast migration of CH4 front leads to the shrinkage of miscible/near-miscible zone, which is not conducive to CO2 flooding. Finally, the CO2 injection concentration of non-breakthrough stage, breakthrough stage and large-scale breakthrough stage was determined to be 78.3%, 61.5% and 29.2%, respectively. This work provides strong evidence for the treatment of associated gas reinjection, which is beneficial for optimization of carbon capture, EOR-utilization and storage (CCUS-EOR) projects.

Pore pressure prediction of hydrocarbon reservoirs with empirical models and artificial neural network: case study in the Doba basin, Chad

Accurate Pore pressure prediction is essential in drilling as it enables drilling hazards to be avoided. However, traditional methods of pore pressure prediction, especially empirical methods are field-specific. It is therefore important to evaluate the best empirical method which is to be applied in any basin or field according to its main characteristics. Besides, recently, artificial neural networks (ANNs) are the most used for pore pressure prediction because they can help to learn complex relationships between input and output parameters. They lead to accurate pore pressure prediction results in many cases. In light of this, the aim of this study carried out in the Doba basin is to analyse and compare the applicability of various sonic log-based empirical models of pore pressure prediction, including Eaton’s model, Raymer-Hunt’s model and Kozeny-Carman’s model and a ANN model of pore pressure prediction in order to find out the best predictive one to use in the studied area in order to achieve better prediction results. To achieve this objective, firstly, the mathematical models of pore pressure prediction from Eaton, Terzaghi and Raymer-Hunt equations and Kozeny-Carman’s model were used. The artificial neural network method uses 33 datasets of well log data including sonic transient time, vertical stress and porosity as input parameters to train the ANN model. The output parameters are the measured pore pressures produced by the Repeat Formation Tester. Using 70% of data set for training, 15% for test and 15% for validation, the trained model with the Bayesian Regularization Backpropagation function predicts pore pressure with an average correlation coefficient of 98%. The results show that pore pressure obtained from the Kozeny-Carman’s model, also has a 98% correlation coefficient, thus proving to be the most accurate of empirical methods. Indeed, pore pressures obtained from Raymer-Hunt’s model and Eaton’s model have 97% and 90% respectively as correlation coefficients. This study provides the best and most reliable empirical method of sonic log-based pore pressure prediction to use in the Doba basin, which can be used to achieve the best pore pressure prediction results and hence ensures drilling safety and wellbore stability in the studied area. The study also highlights a good application of the Bayesian function of the ANN for pore pressure prediction in the investigated area.

Depositional, stratigraphic and structural controls on the geometry of Montney Formation reservoirs: Lower Triassic, northeast British Columbia, northwest Alberta

Abstract The Lower Triassic Montney Formation is a world-class unconventional hydrocarbon reservoir that spans the border of northeast British Columbia and northwest Alberta. Integrated sedimentological and ichnological analyses suggest that the Montney Formation was deposited in a predominantly prodeltaic setting that was commonly influenced by both river flood and storm processes. Riverine processes include the local occurrence of normally- and inversely-graded siltstone and sandstone interbeds, interpreted as the record of sediment-laden hyperpycnal flows. Episodic storms are recorded by the local occurrence of hummocky cross-stratified interbeds, as well as normally graded, parallel and wave-ripple laminated beds, which are commonly draped by structureless carbonaceous mudstones. These mudstone drapes represent river-flood-derived fluid muds that collapsed from hypopycnal plumes following the passage of the storms and suggest the intimate linkage between storms and heightened fluvial discharge. The basin in which the Montney Formation was deposited began as three sub-basins, northern, central and southern, each of which experienced different patterns of subsidence and uplift that varied both spatially and temporally during sedimentation. Subsidence of the northern sub-basin was compartmentalized by deep seated faults that provided accommodation for the basal sequence of the Montney Formation, Sequence 1. Subsequent fault movement resulted in reduced accommodation in the northern sub-basin and accelerated subsidence in the central sub-basin, providing accommodation for deposition of Sequence 2, the basal sequence in the central sub-basin. The northern sub-basin remained paleotopographically elevated throughout deposition of Sequence 2 and early Sequence 3 successions, and these younger units did not extend beyond the northern limit of the central sub-basin. During subsequent deposition of the late Sequences 3 and Sequence 4 successions, compartmentalization between the north and central sub-basin was greatly reduced and these intervals were deposited relatively more uniformly along-strike. The unconventional and conventional reservoirs in both the northern and central sub-basins occur at the scale of systems tracts within the four depositional sequences of the Montney Formation. Reconstructing the depositional history of the component systems tracts of Sequence 1 through early Sequence 3 reveals the dynamic interplay between syndepositional tectonism, fluctuating relative sea-level and deltaic depositional processes in controlling the character, geometry and distribution of prolific Montney Formation reservoirs. The recognition of these key geological controls enhances predictability in this valuable resource and may be applicable to other fine-grained reservoirs elsewhere.

A Spatially Restricted Distribution of Thermophilic Endospores in Laptev Sea Shelf Sediments Suggests a Limited Dispersal by Local Geofluids.

Thermospores, the dormant resting stages of thermophilic bacteria, have been shown to be frequent but enigmatic components of cold marine sediments around the world. Multiple hypotheses have been proposed to explain their distribution, emphasizing their potential as model organisms for studying microbial dispersal via ocean currents. In the Arctic Ocean, the abundance and diversity of thermospores have previously been assumed to be low. However, this assessment has been based on data mainly from the western fjords of Svalbard, thus leaving most of the Arctic unexplored. Here, we expand the knowledge about the distribution of thermospores in the Arctic Ocean by investigating the abundance and diversity of thermospores in heated shelf sediments from three sites in the outer Laptev Sea. Two of the sites are located in an area with methane-emitting cold seeps with a thermogenic source signature suggestive of an origin in a deep hydrocarbon reservoir, while the third site is a reference site not known to be impacted by seepage. We found that activity of viable thermospore populations was more prominent at one of the investigated seep sites. This finding is supported by both radiotracer growth experiments showing thermophilic, sulfate-reducing activity triggered by heating, as well as 16S gene sequence analyses showing significantly enriched ASVs affiliated to the phylum Firmicutes following high-temperature incubations. An enrichment of the sulfate-reducing, endospore-forming class Desulfotomaculia in heated samples compared to unheated samples was also observed. Furthermore, several ASVs identified at the seep site are closely related to thermospore-producing bacteria associated with the deep biosphere, including hydrocarbon and hydrothermal systems. Based on the combined information from induced activity, estimated abundance, and phylogenetic composition using 16S rRNA gene sequencing, we propose likely source environments and dispersal vectors for thermospores in the Arctic Ocean.

Evaluation of micro-dispersion on oil recovery during low-salinity water-alternating-CO2 processes in sandstone cores: An integrated experimental approach

Low-salinity water (LSW) and CO2 could be combined to perform better in a hydrocarbon reservoir due to their synergistic advantages for enhanced oil recovery (EOR); however, its microscopic recovery mechanisms have not been well understood due to the nature of these two fluids and their physical reactions in the presence of reservoir fluids and porous media. In this work, well-designed and integrated experiments have been performed for the first time to characterize the in-situ formation of micro-dispersions and identify their EOR roles during a LSW-alternating-CO2 (CO2-LSWAG) process under various conditions. Firstly, by measuring water concentration and performing the Fourier transform infrared spectroscopy (FT-IR) analysis, the in-situ formation of micro-dispersions induced by polar and acidic materials was identified. Then, displacement experiments combining with nuclear magnetic resonance (NMR) analysis were performed with two crude oil samples, during which wettability, interfacial tension (IFT), CO2 dissolution, and CO2 diffusion were quantified. During a CO2-LSWAG process, the in-situ formed micro-dispersions dictate the oil recovery, while the presence of clay minerals, electrical double-layer (EDL) expansion and multiple ion exchange (MIE) are found to contribute less. Such formed micro-dispersions are induced by CO2 via diffusion to mobilize the CO2-diluated oil, alter the rock wettability towards more water-wet, and minimize the density contrast between crude oil and water.

Time Dependent Spectral Ratio Technique for Micro-seismic Exploration in the Niger Delta Region of Nigeria

Abstract: Since the discovery of the hydrocarbon micro-tremors, there have been numerous efforts to understand the causes of these microseisms related to oil and gas. A spectral ratio (SR) time-dependent equation was derived based on geological principles. The equation showed tremendous success in analyzing multi-layered geological terrain and estimating the spectral ratio in the Niger Delta region of Nigeria. This study seeks to develop a reliable model using standard seismic reflection data to analyze microseismic datasets from hydrocarbon reservoirs. Type A-SR acts over a longer duration and can be used to determine hydrocarbon reservoirs. Type B-SR acts in a short time with maximum impact. It can be used to determine gas condensate flow in the hydrocarbon reservoir. It is recommended that this technique be applied in real time to ascertain its accuracy. Keywords: Niger Delta, Microseismic, Amplitude, Special ratio, Geology.

Characterization of Depleted Hydrocarbon Reservoir AA-01 of KOKA Field in the Niger Delta Basin for Sustainable Sub-Sea Carbon Dioxide Storage

Characterization of Depleted Hydrocarbon Reservoir AA-01 of KOKA Field in the Niger Delta Basin for Sustainable Sub-Sea Carbon Dioxide Storage