Hydrocarbon Reservoirs Research Articles

Digital rock modeling of deformed multi-scale media in deep hydrocarbon reservoirs based on in-situ stress-loading CT imaging and U-Net deep learning

Deep and ultra-deep hydrocarbon reservoirs are regarded as an attractive target for onshore oil and gas exploration and development in China. The multi-scale fractures are widely distributed in this type of reservoir. The fluid-solid coupling effect is strong, which can greatly affect the fluid flow, resulting in a low hydrocarbon recovery with the average value less than 15%. To explore the underlying flow dynamics during efficient development of deep and ultra-deep hydrocarbon reservoirs, it is of great importance to characterize the multi-scale fracture-pore structure evolution of rock affected by strong geo-stress field variation. To tackle the above issues, an actual rock drilled from a typical ultra-deep reservoir in Tarim Basin are selected to conduct in-situ stress-loading computed tomography (CT) scanning experiments, and the CT gray images of rock microstructure under different dynamic loading conditions are obtained. A fully convolutional neural network (U-Net) deep learning segmentation algorithm is introduced to accurately distinguish the rock skeleton, pore space and fractures in deep rock. The three-dimensional (3-D) digital rock model of deformed multi-scale fracture-porous media under different dynamic loading conditions is ultimately established to investigate the evolution of fracture morphology and deep rock microstructure as the in-situ stress is gradually loaded. It indicates that, the U-Net deep learning semantic segmentation algorithm can accurately segment CT images of deep rocks, and the established 3D digital rock model of fractured porous media can accurately represent the pore-throat distribution, fracture morphology, and pore-scale topological connectivity. At the initial stage of stress loading, there are few micro-fractures inside the rock, and the fracture connectivity is poor. Due to effect of rock compaction, the average pore throat radius increases while pore throat ratio, coordination number and tortuosity greatly decrease. As the effective stress is gradually loaded, the micro-fractures begin to propagate, leading to stronger heterogeneity of micro-fractures’ distribution and better topological connectivity, and both the coordination number and tortuosity gradually increase. After the deep rock is fractured, micro-fractures run through a fracture network and all the above topological parameters increase greatly.

Sensitivity analysis of a dual-continuum model system for integrated CO2 sequestration and geothermal extraction in a fractured reservoir

Depleted hydrocarbon reservoirs are considered as the most feasible option for CO2 geological sequestration and utilization. Most of the hydrocarbon reservoirs are naturally fractured. Simulation of fluid flow and heat transfer in these fractured formations remains a significant challenge in reservoir engineering. In this study, a dual-continuum model is developed to simulate integrated CO2 sequestration and CO2-circulated geothermal extraction in a fractured reservoir block in North Oman. The high-dimensional sensitivity of key parameters controlling CO2-brine flow and heat transfer in this matrix-fracture system is quantitatively evaluated by an efficient surrogate modeling approach. The surrogate models are constructed and validated based on a suite of physics-based model simulations. It is found that fracture permeability dominates the CO2 injectivity, storage, circulation and associated geothermal extraction. Response surface analysis shows that the flow area density between matrix-fracture and matrix block length controls the flux interaction between matrix and fracture formations. In contrast, the fracture aperture shows negligible influence in the dual-continuum modeling system. Particularly, sensitivity varying with locations on the response surface is analyzed for defined performance indicators.

Artificial SLiMEs and gas storage in deep subsurface.

Over the next few years, it is planned to convert all or part of the underground gas storage (UGS) facilities used for natural gas (salt caverns, depleted hydrocarbon reservoirs and deep aquifers) into underground hydrogen (H2) storage (UHS) reservoirs. These deep environments host microbial communities, some of which are hydrogenotrophic (sulfate reducers, acetogens and methanogens). The current state of microbiological knowledge is thus presented for the three types of UGS facilities. In the mid-1990s, the concept of anaerobic subsurface lithoautotrophic microbial ecosystems, or SLiMEs, emerged. It is expected that the large-scale injection of hydrogen into subsurface environments will generate new microbial ecosystems called artificial SLiMEs, which could persist over time. These artificial SLiMEs could lead to hydrogen loss, an intense methanogenic activity, a degradation of gas quality and a risk to installations through sulfide production. However, recent studies on salt caverns and deep aquifers suggest that hydrogenotrophic microbial activity also leads to alkalinisation (up to pH 10), which can constrain hydrogenotrophy. Therefore, studying and understanding these artificial SLiMEs is both a necessity for the development of the hydrogen industry and presents an opportunity for ecologists to monitor the evolution of deep environments in real time.

CHARACTERIZATION OF A FLUVIAL DELTAIC SALT-INFLUENCED SYSTEM FOR CO2 STORAGE USING SEISMIC POST-STACK INVERSION AND SELF-ORGANIZING MAPS IN THE UPPER MIOCENE, ONSHORE LOUISIANA

Basins that have historically been explored for hydrocarbons are now seen through a new perspective for carbon capture and storage. Legacy hydrocarbon reservoirs may now have the potential to become carbon storage targets. The Miocene Sandstone in south Louisiana is a stratigraphic interval that contains favorable zones for carbon storage, and seismic interpretation is a critical tool for characterizing these sands and estimating the amount of possible carbon storage. New workflows leveraging machine learning and seismic inversion can be applied to legacy fields to generate a new estimate for pore space and carbon storage capacity. The study area contains a 3D seismic survey covering 310 mi2 (803 km2) and 16 wells. Using these data, the workflow leverages self-organized maps (SOM) to identify zones of interest both laterally and vertically for carbon storage. SOM provides an uplift in resolution for interpretation compared to single attributes. A model-based acoustic impedance inversion produces porosity information that is used in tandem with SOM outputs. The acoustic impedance results strongly correlate to porosity within the target sands, and the SOM and porosity maps delineate specific sand lobes for potential storage. Wellbore data within the sand lobe align with SOM and inversion results and show rock quality with 26% average porosity and 90 feet gross thickness. The research highlights a project sized target within the middle Miocene containing 10.3 Megatons of estimated CO2 storage. Using SOM and inversion maps in tandem is an effective way for screening an area for carbon storage targets.

Hazard Identification of Well Test Operation in Drilling and Production Offshore Platform by HAZID

A significant portion of energy resources has been discovered in offshore sectors, leading to a continuous increase in the volume of activities and operations. Once a well is drilled and fluid extraction begins, all the reservoir parameters, start to change. well test operation is one of the most crucial tools for engineers to comprehend the behavior and parameters of hydrocarbon reservoirs. In this study, the hazards associated with the well test operations has been identified by using HAZID technique. A total of 189 risks were identified in the initial risk assessment, with 35 categorized as low risk, 88 as medium risk, and 66 as high risk and after implementing protection layers in the secondary risk assessment, the number of low risks incidents increased, while medium and high-risk incidents were reduced significantly. Most of the risks identified are associated with loading operations and sea transportation from the port to the drilling rig. Given that loading and unloading operations are among the most frequently repeated activities in well testing operations, it is determined that they play a critical role in the overall risk profile

A new expression for fluid factor using AVO intercept and gradient: Theory and application on gas sand reservoirs from offshore Australia

Numerous amplitude variation with offset (AVO) fluid indicators have proven to be sensitive to the presence of hydrocarbons. Mathematically, these fluid indicators measure the deviation of seismic responses of hydrocarbon reservoirs from their background in a specific domain. We develop a new expression for the fluid factor commonly used in AVO analysis and interpretation. The expression is a function of the common AVO intercept and gradient, along with a weighting coefficient that suppresses the contribution of lithology and other factors unrelated to fluid content. The coefficient also assists in calibrating the fluid factor to the local geology. We compare the performance of our fluid factor with existing fluid factors. All the fluid factors are tested on a worldwide collection of P- and S-wave velocity and density measurements. The testing is followed by application on synthetic data before applying the attribute on real data from the Northwest Shelf of Australia. In the latter application on the real data, we use two wells for calibration purposes, and the third as a blind well. Our fluid factor demonstrated high capability in detecting the targeted gas zones at the three well locations and identifying new prospective zones.

Characteristics and formation of natural fractures in a silica-rich chalk, Coniacian Arnager Limestone Formation, Bornholm, Denmark.

Natural fractures are abundant and important components in many carbonate sedimentary rocks globally. In hydrocarbon and groundwater reservoirs of carbonate rocks they can form connected networks and thereby influence the permeability and f luid flow significantly. Outcrop studies of fractured carbonate rocks can provide an essential understanding of 3-dimensional fracture networks, thereby aiding in understanding fracture patterns and connectivity in subsurface carbonate reservoirs. The Arnager Limestone Formation is a naturally fractured silica-rich chalk of Coniacian age exposed in a coastal cliff on the island of Bornholm in the Baltic Sea (Denmark). This study examines the natural fractures in the Arnager Limestone Formation from a structural and geomechanical perspective. The Arnager Limestone Formation forms one, 12–20 m thick, main rock mechanical unit; bedding planes acts as weak interfaces and divides it into near-identical, cm- to dm-thick rock mechanical subuits. Flat-lying (horizontal) or low-angle dipping bedding-parallel fractures are intersected by two near-vertical or steeply dipping fracture systems, a major N–S-trending system and a less prominent W–E-trending fracture system. Rock mechanical analysis of the tensile strength and elastic moduli provides the foundation for discussing maximum burial depth of the Arnager Limestone Formation. The tensile strength gives information on the bedding-parallel fractures, which can have formed due to stress relief during uplift and erosion, possible accentuated by glacial processes. The near-vertical fracture sets are interpreted to have formed in response to tectonic movements.

Phase behavior analysis of methane confined in nanopores using molecular simulation

Interest in the phase behavior of hydrocarbons in shale reservoirs has grown in recent years. Petroleum fluid phase behavior has been observed to differ significantly between conventional reservoirs and shale reservoirs. Within shale reservoirs, notable surface-fluid interactions can lead to non-uniform molecule distribution and an alteration in fluid phase behavior, primarily caused by the existence of nano-scale porous materials. In this work, we study the phase behavior of methane in single cylindrical pore models. We apply the gauge Gibbs ensemble Monte Carlo (gauge-GEMC) simulation technique to investigate the phase behavior of methane in 4–10 nm single nanopores and calculate the saturation pressures at various temperatures using the grand canonical Monte Carlo (GCMC) simulation technique. A shift in the phase diagram has been found for methane in nanopores. As pore size decreases, the shift becomes more significant.

Hydrocarbon charge history of deeply buried clastic reservoirs in the Bozi area of the Kuqa Depression, western China: implications for deep and ultra-deep petroleum exploration

Significant progress has recently been made in deep and ultra-deep oil and gas exploration globally, demonstrating enormous exploration potential of the deep and ultra-deep strata. However, the accumulation and preservation pattern of deep and ultra-deep oil and gas remains poorly understood, greatly impeding further petroleum exploration and development in the deep and ultra-deep strata. By taking the Bozi deep and ultra-deep condensate gas reservoirs in the Kuqa Depression, western China as an example, we attempt to reconstruct the hydrocarbon charge history in such deep reservoirs via an integrated investigation involving quantitative grain fluorescence, fluid inclusion petrography and microthermometry, micro-fluorescence spectroscopy, laser Raman spectroscopy, PVTx modelling, and basin modelling. The results show that: (1) The Bozi deep and ultra-deep reservoirs contain one group of gas inclusion assemblage, and two groups of oil inclusion assemblages, with one being characterized by near yellowish-whitish and blue-whitish diphasic or triphasic oil inclusions, and the other being featured by bright blue diphasic oil inclusions; (2) The first oil charge occurred during the Early Neogene (6.5–5.5 Ma), and the second oil charge occurred during the Late Neogene (4.4–3.5 Ma), under normal hydrostatic pressure or slightly weak overpressure; and (3) The gas charge occurred during the Pleistocene (∼1.6 Ma), with a corresponding reservoir pressure coefficient of approximately 1.7, transforming the reservoir fluid phase state from black oil or volatile oil to condensate gas. Our findings highlight that aside from the present burial depth, a favorable burial history model is crucial for the preservation of liquid hydrocarbons in deep and ultra-deep reservoirs. The occurrence of liquid hydrocarbons in the Bozi deep and ultra-deep condensate gas reservoirs with depths over 7,000 m is benefited from a prolonged period (>100 Ma) of shallow burial and a late-stage (since 10 Ma) rapid subsidence.

Sedimentary characteristics and reservoir architecture of a lacustrine mixed carbonate/siliciclastic system: the lower member of the ShangGanchaigou Formation, Neogene, in the western Qaidam Basin, China

Lacustrine mixed carbonate/siliciclastic sediment is an important type of oil and gas reservoir with significant potential. Although previous studies have investigated the sedimentary characteristics of the mixed depositional system in numerous oil and gas-bearing basins worldwide, a detailed sedimentary architecture model is still lacking for guiding reservoir characterization at the hydrocarbon reservoir scale. In this paper, a typical lacustrine mixed carbonate/siliciclastic sedimentary system, preserved in the lower member of the ShangGanchaigou Formation, Neogene, in the western Qaidam Basin, Western China, was deeply investigated based on well logging data from 640 wells, 438 m of cores from 3 core wells, and outcrop studies. The results demonstrate that 1) seven types of architecture elements, namely, distributary channel, channel mouth bar, distal bar, sheet-like sand, shallow water mud, algal mound, and marl flat characterized by different lithofacies associations, were recognized based on core and well logging data. 2) The lacustrine mixed carbonate/siliciclastic depositional system can be divided into three facies belts. Along the lakeward direction, the proximal facies belt is dominated by delta front deposits and characterized by gradually downstream bifurcating distributary channels and associated lateral amalgamated delta lobes. The middle facies belt is characterized by isolated and small-scale delta lobes and inter-lobe deposits, including sheet-like sand, small-scale algal mounds, and marl flats, and the distal facies belt is a combination of large-scale algal mounds and marl flats. 3) Within a depression, short-term base-level cycles controlled the facies belt transition, and the proximal, middle, and distal facies belts formed under relatively low, middle, and high base-level conditions, respectively. 4) The scale and connectivity of reservoirs gradually decreased from the proximal to the distal belt.

Seismic reflection data interpretation and petrophysical evaluation of the Meyal area, the Potwar Basin, Pakistan

Despite extensive exploration efforts in the Potwar Basin, a thorough understanding of the structural framework and reservoir characteristics within the Meyal Field remains critical for pinpointing potential hydrocarbon zones. This study aims to integrate geology and geophysics to emphasize the structural and stratigraphic interpretation of the Meyal Field, including reservoir characterization using seismic and well-log data. The seismic interpretation of six seismic lines focuses on four key reflectors: the Kamlial, Chorgali, Sakesar, and Salt Range Formations. The Eocene Chorgali and Sakesar Formations are of primary importance for exploration and production. Structural analysis revealed that the Meyal anticline is a plunging structure bounded by a back thrust to the north and a fore thrust to the south, suggesting a favorable location for hydrocarbon accumulation. Time-depth contour maps derived from seismic data further delineate potential sites for future investigations. The well correlation indicated an uplift toward the Meyal-2 compared with Meyal-5, signifying a shallowing trend attributed to thrust tectonics. This tectonic regime has rendered the area highly prospective for hydrocarbon exploration, with thrusting and oblique-slip faulting enhancing the reservoir qualities of Eocene Formations. The petrophysical evaluation revealed favorable reservoir characteristics, including an average porosity ranging from 0% to 12% with an effective porosity of approximately 7.5%, water saturation up to 42%, and hydrocarbon saturation reaching 58% within the pay zone of the reservoir. These findings suggest that the Sakesar and Chorgali Formations within the Meyal oil field hold promise as productive hydrocarbon reservoirs. The integrated study provides valuable insights into the structural framework and reservoir characterization, highlighting the potential of the Eocene Formations as productive hydrocarbon reservoirs supported by favorable structural configurations and petrophysical properties.

Novel Acinetobacter sp. Isolated from Oil-contaminated Soil for Microbial Enhanced Oil Recovery

The viscosity of hydrocarbon reservoirs increases with age. So, a significant amount of oil is trapped in the underground reservoirs after recovery using primary and secondary methods. To improve the recovery, tertiary methods have been used. However, there is limited research on Microbial Enhanced Oil Recovery (MEOR) as a tertiary method due to microbes' inability to survive the high-temperature reservoir conditions. Consequently, the goal of this research is the creation of a novel bacteria strain for MEOR. The isolated bacteria colonies were inoculated in a batch fermentation broth, and the biosurfactant produced was screened using the oil displacement, emulsification index, modified drop-collapse test, surface tension, and interfacial tension criteria. The effects of pH (7.2 – 10.52), and salinity (15 – 35 %) at optimum temperature were studied on the selected isolate, which was identified by partial 16 rRNA gene sequence analysis. Gas Chromatography-Mass Spectroscopy was used to characterize the biosurfactants produced. The new isolate reduced heavy oil viscosity by 17% and produced a recovery factor in the range of 13-16.72%. The new bacteria is a thermophile and survived at a temperature of 65 °C, indicating promise for use in MEOR.

Optimizing reservoir characterization: insights from integrated data analysis

The Onshore Hydrocarbon prospectivity of the Niger Delta X-field is examined through the integration of 3D seismic and recorded information from well log data. Probable reservoirs of hydrocarbon-bearing were delineated to tackle the non-uniqueness in the identification of hydrocarbon quantity of concern. Three significant faulting patterns or systems were delineated and their architectural attributes depict a typical Niger Delta embedded anticlinal structural pattern. The study field exhibited both synthetic and antithetic structures, hence only fault on delineated reservoirs was used for structural modeling. All well locations were sited within the fault-supported synthetic and anticlinal structures and the static characteristics within the well coordinates were analyzed through petrophysical assessment. Depicted reservoir sands show low gamma ray readings, low volume of shale, considerate hydrocarbon saturation and low water saturation. The established petrophysical models showed a better net-to-gross (NTG) ratio, for the entire delineated reservoir units. This has contributed to the assessment of hydrocarbon-bearing reservoir units before employing the strategy for field development scenario, in order to eliminate dry hole drilling campaign. These will contribute to the reduction of operational costs, having delineated the accurate geometry and petrophysical model of hydrocarbon reservoir units.

Improving the training performance of generative adversarial networks with limited data: Application to the generation of geological models

In the past years, there is a growing interest in the applications of Generative Adversarial Networks (GANs) to generate geological models. Although GANs have proven to be an effective tool to learn and reproduce the complex data patterns present in some geological models, some challenges still remain open. Among others, a well-noticed problem is the need for a large number of samples to ensure high-quality training, which can be prohibitively expensive in some cases. As an attempt to offer a (possibly partial) solution to the aforementioned challenge, in this study, we investigate the feasibility and effectiveness of a zero-centered discriminator regularization technique for improving the performance of a GAN. Additionally, we evaluate an adaptive data augmentation technique to overcome the potential issue of limited training data, for the purpose of generating geologically feasible realizations of hydrocarbon reservoir models. Our findings demonstrate that a combination of the two techniques lead to notable performance improvements of a GAN. Particularly, it is observed that using the adaptive data augmentation technique in a GAN can yield similar results to those obtained by the GAN with a much larger dataset.

Early extensional salt tectonics controls deep-water sediment dispersal

Predicting the distribution of sedimentary facies during the early stages of deformation of salt-detached continental margins is key to constraining the location and stratigraphic architecture of hydrocarbon and CO2 reservoirs, as well as to understanding the oceanic carbon cycle. Despite its importance, we still have a relatively poor understanding of salt-sediment interactions during the early phases of extensional salt tectonics, mainly because subsequent salt-related deformation and/or deep burial of the related stratigraphic succession means the related deposits are poorly imaged in seismic reflection data and/or not penetrated by borehole data. We investigated the interplay between early extension-related salt deformation and deep-water sediment dispersal using 3-D seismic reflection data from the northern Levant Basin offshore Lebanon. Our results indicate that salt tectonics has two contrasting impacts: Whereas slope-parallel faults favor early sediment transfer along downslope-oriented corridors to the abyssal plain, slope-normal faults and ramp-syncline basins trap land-derived sediments, hampering or delaying their transport to the abyssal plain. These results help refine source-to-sink models of turbidite systems developing in young salt basins, highlighting the crucial role of extensional tectonics in controlling sediment dispersal and the development of intra-slope depocenters and emphasizing the impact of fault strike, ramp-syncline basin evolution, and salt thinning. Our study has significant implications for predicting the location of deep-water coarse-grained sediment and the preservation of land-derived organic carbon in mature, more structurally complex, salt basins.

Evaluating the efficacy of water alternating gas injection technique in the upper jurassic hydrocarbon reservoirs, considering saturation pressure

A tertiary method of enhanced oil recovery (EOR) based on the watergas alternating injection process (WG) is examined in this article based on the ratio between saturation pressure and reservoir pressure. A hydrodynamic simulation of the WAG process was carried out using TEMPEST MORE software (version 7,1). Many hydrocarbon fields worldwide are currently experiencing declining production rates. However, by utilizing advanced technologies like alternate injection of water and associated petroleum gas, the final oil recovery factor (RF) can be significantly increased. To ensure successful water injection experiments in real fields, it is crucial to consider the ratio of saturation and reservoir pressures during injection. Any negligence in this regard can lead to failure of the experiments aimed at enhancing oil recovery through WAG application. The research examines two variations of reservoir system models with certainty. In the initial model, the saturation pressure is lower than the reservoir pressure, signifying an under-saturated state of the reservoir system containing dissolved gas. Consequently, when accompanying petroleum gas is introduced, it mixes with oil at precise thermobaric conditions. According to the second model, the reservoir is saturated with gas at a saturation pressure equivalent to the formation pressure. A thorough assessment indicates that the success of water alternating gas injection (WAG) is heavily influenced by the initial state of the reservoir. In situations where the reservoir is already saturated with gas, implementing water-gas stimulation may be ineffective as gas breakthroughs may occur rapidly. However, implementing WAG in saturated reservoirs can lead to a 1 – 8% rise in overall oil production, observable within 3 – 4 years, depending on the timing after waterflooding. Simultaneously, in the case of reservoirs with a low saturation pressure, which exhibits an undersaturated reservoir system, the implementation of water alternating gas injection can be seen as a viable approach for enhancing oil recovery. WAG is a proven method that confidently increases oil recovery up to 10% in undersaturated reservoirs compared to conventional waterflooding.

High resolution 3-D seismic and sequence stratigraphy for reservoir prediction in ‘Stephi’ field, offshore Niger Delta, Nigeria

The Offshore Niger Delta, Nigeria, stands as a dynamic geological marvel, known for its intricate processes and extensive hydrocarbon reservoirs. This study employed an integrated approach, utilizing 3D seismic data and well logs, to conduct a thorough analysis of sequence stratigraphy and reservoir characterization in the pursuit of optimizing hydrocarbon exploration in the region. The study focused on the NW–SE trending Miocene depocenters, which predominantly comprises alternating sandstone and thick shale layers within the Agbada Formation. These reservoir units showcased stacked shallow marine fluvial–deltaic sediments, separated by significant marine shale units. Within the study area, two hydrocarbon-bearing reservoirs were identified and named: R1 and R2. Petrophysical analysis identified R2 as the most promising reservoir, with a permeability of 1184 × 10− 3 µm2, 85% hydrocarbon saturation, porosity of 0.30, and effective porosity of 0.27. Fault structural analysis uncovered that hydrocarbons are trapped within a network of growth faults within the wave-dominated Niger Delta depositional system. From the sequence stratigraphic interpretation, four depositional sequences were delineated between the depths of 2030–3417 m, and are bounded by five sequence boundaries. Integrated seismic facies analysis revealed high-energy feeder systems likely supplying sediments from river sources to offshore locations. These integrated findings provide essential insights to inform resource management, exploration strategies, understanding of reservoir distribution, and structural intricacies within the complex offshore Niger Delta, Nigeria, providing valuable information. The depositional environment helped in the understanding of the stratigraphic traps which are prospects in the study area. This together with the associated reservoir quality allowed accurate prediction for potential reservoir facies and will further improve the field development plans.

Rhenium-platinum group elements reveal seawater incursion induced massive lacustrine organic carbon burial

Organic carbon burial in ancient lacustrine settings is a crucial source of petroleum resources. Unlike the marine environment, the dynamics of organic carbon burial in the terrestrial realm are more complex due to the interplay of global and regional climate-tectonic factors. There appears to be a potential linkage between seawater incursion events (SWIEs) and the generation of lacustrine source rocks. However, reliable proxies to reconstruct the frequency and extent of SWIEs are currently lacking. Here, we explore the potential of rhenium-platinum group elements (Re-PGE) system as a novel proxy for determining SWIEs in the Nenjiang Formation of the lacustrine Songliao Basin in China that is noted for its high-quality source rock. By comparing marine and non-marine intervals, we validate the utility of Re-PGE fractionation patterns and osmium (Os) isotope compositions. Moreover, the Re/Ir ratios demonstrate two main episodes of quantitative seawater-lake water exchange. The comparison of variable indicators shows that the Re-PGE system is more sensitive to the changes in water sources, thus providing detailed information of frequency and exchange amount. The inverse variation between seawater contribution and total organic carbon content further implies that the massive sulfate influx from SWIEs facilitated bacterial sulfate reduction in the sediment pile, which had the effect of recycling nutrients (e.g., phosphorous) back into the water column. The SWIEs-triggered eutrophication induced a positive feedback loop between productivity and hypoxia, creating ideal conditions for the preservation of organic carbon. Our data reveals the detailed mechanism of SWIEs-triggered organic carbon burial and emphasizes the significant role of SWIEs in generating economically important hydrocarbon reservoirs.

Reconstruction of Subsurface Potential Hydrocarbon Reservoirs Through 3D Seismic Automatic Interpretation and Attribute Analysis

Reconstruction of Subsurface Potential Hydrocarbon Reservoirs Through 3D Seismic Automatic Interpretation and Attribute Analysis

Petrophysical identification and characterization of Cenozoic hydrocarbon reservoir zones at the R field, northern Rovuma Basin, Tanzania

ABSTRACT Cenozoic reservoirs of northern Rovuma Basin, Tanzania, have not yet been characterized in detail. Combined well log patterns and fracture indicators have not been presented before. This work used petrophysical analysis of density, neutron, gamma ray (GR), resistivity and sonic well logs to characterize reservoir zones at the study area. Twelve reservoir zones (A–L) have been identified based on lithological properties and resistivity anomalies. The presence of hydrocarbons in these zones is concluded based on acoustic parameters involving acoustic impedance and V p / V s ratio, and ∆TC and neutron porosity crossplots. Fractured sedimentary fills in different stratigraphic levels were assessed based on resistivity-logs crossplots. Results show that eleven zones (A–F and H–L) are gas-filled and zone G is devoid of hydrocarbon. We have shown that, in areas with resistivity anomaly, all GR-resistivity combined patterns may be used to indicate hydrocarbon bearing layers except when there is a co-occurrence of funnel-shaped pattern for both logs. Distribution of fractures and hydrocarbons suggest the existence of compartmentalized reservoirs. These reservoirs have been discussed based on a geoseismic model created to support our arguments. Our technique has allowed easier identification of hydrocarbon bearing zones through well Rx. This technique may be applied in other sedimentary basins.