Hydrocarbon Trap Research Articles

Hydrocarbon Potential Evaluation of Chad Basin, Northeastern Nigeria Using High-Resolution Aeromagnetic Data

A cost-effective and non-intrusive aeromagnetic geophysical technique was utilized to reduce exploration uncertainty in the Chad Basin, which is believed to have significant hydrocarbon potential despite limited exploration due to its remote and challenging terrain. By analyzing various derivatives and magnetic attributes extracted from filtered and enhanced aeromagnetic data, the study aimed to highlight potential areas for hydrocarbon generation and preservation, allowing for more focused and detailed geophysical exploration efforts. This study produced several key maps, including a total magnetic intensity map (ranging from -168.7 to 224.8 nT), a reduction to equator map (ranging from -156.8 to 207.9 nT), and depth analysis, which helped delineate the structural framework and sedimentary thicknesses within the basin. Quantitative interpretation of these maps, along with the analytic depth map (ranging from 22.1 to 5649.3 m), tilt depth map (ranging from -76.50 to 80.40), and first and second vertical derivatives maps (ranging from -0.097 to 0.086 nT/m and -0.000240 to 0.000236 nT/m, respectively), was employed to detect geological features and thick sedimentary fills sufficient to create or trap hydrocarbons. Depth estimates indicate that the shallow sources range between 22 and 230 m, while deeper sources fall between 2747 and 6000 m, suggesting sufficient sedimentary fill for hydrocarbon generation. The basin is characterized by large sedimentary deposits that are bounded by structural features such as folds, faults, and fractures. The northern part of the basin, trending towards the northwest, eastern edge, and parts of the south, showed active structural features, including anticlines, synclines, and fractures, which are essential for petroleum trapping. These findings, coupled with the identified thicknesses and favorable structural disposition, suggest that the Chad Basin holds high potential for hydrocarbon accumulation, making it a prospective region for further exploration with more detailed geophysical methods.

The Life and Death of Hydrocarbon Traps in East Greenland: The Charge and Degradation Histories of Laplace Bjerg and the Mols Bjerge

ABSTRACTThe exhumed hydrocarbon traps of East Greenland provide a superb opportunity to study the evolution of fluid flow in the petroleum systems of the North Atlantic. Following basin inversion during the Cenozoic these structures were exhumed and deeply incised which has allowed them to be observed and mapped in great detail. This study examines the diagenetic history of the Mols Bjerge and Laplace Bjerg exhumed hydrocarbon traps, from the initial charge of Triassic and Jurassic reservoirs, to their eventual uplift and destruction. Detailed petrographic analysis was undertaken on 67 samples collected at representative intervals throughout the structures. Variations in the distribution of diagenetic phases and remnant porosity were investigated. Twenty three samples were also subjected to helium porosity measurement. Bitumen, up to 18%, was recognised in 34 samples, 6 of which were analysed for their form and reflectance. Fluid inclusion data, collected from the nearby Bjørnedal region, helps to constrain the thermal history of the region. Helium porosity and permeability measurements are low, largely below 10% and 2 mD respectively. However, the abundance of bitumen highlights the presence of significantly higher porosity and permeability during hydrocarbon charge. A synthesis of fluid inclusion data and bitumen reflectance, alongside a detailed examination of the paragenetic sequence, demonstrate that hydrocarbon charge occurred in the Eocene, during maximum burial, at which time only a minor reduction in original intergranular porosities had taken place. The destruction of the pore systems occurred due to the degradation of hydrocarbons to bitumen, resulting from heat flow during intrusive events, and subsequent carbonate and limonite cementation during uplift. The original source of the hydrocarbons is unclear. This work highlights that where unaffected by intrusives and uplift, the largely untested Triassic play may still contain viable reservoir intervals at depth on the Norwegian Continental Shelf.

Three‐dimensional static reservoir modelling of Kareem sandstone reservoir, Tawilla Oil Field, at the southern region of Gulf of Suez, Egypt

The Gulf of Suez, which contains Egypt's oldest oil fields, is one of North Africa's most well‐known oil regions. There are more than 80 conventional oil fields in Egypt's Gulf of Suez, some of which have reservoirs that stretch back to the Precambrian and Quaternary. In close proximity to the southern entrance of the Gulf of Suez is the Tawilla West oilfield. The oil field Tawilla West is believed to consist of rotating fault blocks that descend in a south‐west direction. The main producing reservoirs are the Miocene section reservoirs, the Belayim and Kareem sandstones. The current research is focusing on the structural elements affecting this giant field to update the field structural model using the newly processed 3D seismic survey, the acquired data from newly drilled wells and the associated different logging techniques. The seismic information quality varied from poor to fair. The quality of the interpreted stratigraphic horizons and geological faults was mainly controlled by the seismic information quality. The research used seismic attribute analyses to improve interpretation and incorporate additional features, enabling better hydrocarbon potential identification and characterization of the reservoirs. Several geological structure contour maps and cross‐sections were generated to help in delineating and understanding the reservoir's extension. Based on the detailed correlation study, we were able to detect the faults that affected the structure of the Tawilla West field in detail, define their throw amounts and directions, and identify the missed sections across the studied area. This study introduces an updated model scenario to show the differences and their effect on the field development plan and recommendations. By examining subsurface geologic structural characteristics and evaluating petrophysical data, a 3D static reservoir model was created to resolve structural settings and hydrocarbon trapping, providing detailed information on the field and identifying new opportunities for future development. The research discovered that the updated detailed 3D structural model may support the Kareem Reservoir development plans and encourage drilling, workover and dynamic operations to assign development possibilities in the correct area. According to the established model, there are at least three options in the study's attic areas that might boost oil output and oil reserves for the field while avoiding further failures.

Delineation of deep-seated crustal structures from magnetic data in the southeastern part of the Niger Delta basin, Nigeria

Regional magnetic data in the southeastern segment of the Nigerian Niger Delta were evaluated with the aim of mapping deep-seated tectonic elements. Enhanced filtering operations and 3D forward modelling were applied on the magnetic data. These geologic features triggered the formation of rollover anticlines and faults that serve as structural traps in the study area. The filtered residual magnetic data revealed geologic structures characterized with NE - SW, N - S, and E - W orientations. The 3-D models detected the faulted crustal blocks, gradient zones, and intra-basement compositional magnetic variations. Furthermore, some prominent horst and graben structures as well as related normal faults characterized with distinct magnetic signatures were observed. Faults of base magnetic (of various compositions) were observed to be the fabricating mechanisms of the magnetic anomalies. Collectively, these structures influenced the patterns of magnetic anomalies with direct effects on the hydrocarbon trapping systems, as well as the pathways and accumulation zones for hydrothermal minerals. On the whole, the interpreted results revealed that the basement surface is rippling. Additionally, the depth result showed sedimentary thicknesses that ranged from 4–10 km. Again, the estimated crustal thickness varied from 14 to 19 km. This study has displayed the capabilities of the magnetic method in mapping the depth and configuration of basement rocks, which are crucial in controlling the formation of structural traps. Identifying these basement structures early helps in understanding the overall geological framework and potential hydrocarbon systems.

INTERPRETATION OF MAGNETIC AND GRAVIMETRIC SIGNATURES IN RELATION TO GEOLOGICAL STRUCTURES OF PETROLEUM INTEREST IN THE WESTERN PART OF THE CENTRAL BASIN OF THE DR CONGO

The Cuvette Centrale is a sedimentary basin stretching from the Democratic Republic of the Congo to the Republic of Congo, Gabon and Angola. The existence of hydrocarbons in this large basin is demonstrated by the presence of indications on the DR Congo side and by the discovery of hydrocarbons by the Ngoki well (Republic of Congo) diagonally across the Lokoro sub-basin (DR Congo). In view of this evidence, the four boreholes drilled in the DR Congo's Cuvette Centrale have not reported the presence of hydrocarbons. With this in mind, this study reinterprets the geophysical data (magnetism and gravimetry) to highlight geological structures of petroleum interest. After processing and interpretation, we understand that the region contains interesting structures linked to hydrocarbon trapping. These include anticlines and faults. We discovered that there is a close relationship between the geological structures of these two countries (DR Congo and R Congo). They are all made up of the same geological structures separated by two major strike-slip faults crossed by the Congo River (NE-SW direction). These are the Dextre Fault, which displaces the compartments on the DR Congo side in a SW-NE direction, and the Senestre Fault, which runs NE-SW.

Robust, high-performance Cu-impregnated ZSM-5 zeolites for hydrocarbon removal during the cold-start period: Quantitative elucidation of effects of H+ and Na+ ions on performance and stability

Cu-containing zeolites are suitable for active hydrocarbon (HC) traps. Crucially, physicochemical properties of the zeolite could be finely tuned by varying the ion contents, though such approach has not been used intensively for HC trapping. Therefore, in this study, we adjusted the ratio of Na+ to H+ ions in ZSM-5 zeolites from 1 to 0 and, subsequently, wet-impregnated these zeolites with Cu. A low Na/Al ratio (≤0.4) resulted in marked cold-start test (CST) performance for HC removal in the fresh state (HC removal efficiency of 60.2 %-69.5 %). However, a hydrothermally treated counterpart having an optimal Na+ content (Na/Al ratio of 0.4) could well preserve the original active Cu+ ions along with zeolite structure and, accordingly, show the best CST performance after hydrothermal treatment (HT) at 800 °C (HC removal efficiency of 24.4 % vs. 10.8 % for the conventional H+-form-based one). Furthermore, we investigated adsorption behavior of water and HCs at a deep level and, further, revealed a clear correlation between the HC adsorption ability and CST performance and the representative physicochemical properties (mainly related to Cu+ ions) at all Na+ contents. Additionally, tiny CuO particles on the outer surface of the Cu-impregnated ZSM-5 zeolites having Na/Al ratios of 0–0.4 showed good low-temperature HC oxidation ability (ca. 175–182 °C). Although this HC oxidation ability was reduced after HT, an optimal Na/Al of 0.4 led to preservation of the original ability (ca. 283 °C vs. 320 °C for pure large CuO particles). Finally, we demonstrated a synergistic relationship between Na+ and H+ ion contents (Na/Al ratio of 0.4) that favored the formation of the desired Cu species, thus achieving marked HC adsorption and oxidation after HT.

An optimal combination of Na+ and H+ co-ions for high-performance Cu-impregnated *BEA zeolites: Unravelling the trade-off between the cold-start hydrocarbon trap activity and hydrothermal stability

A Cu-impregnated *BEA (denoted as BEA) type zeolite can serve as an effective hydrocarbon (HC) trap, but its long-term hydrothermal stability should be improved for real uses. However, designing robust high-performance HC traps, which is closely related to the confined environment that accommodates active Cu species and strengthens the zeolite structure, remains elusive. In this study, to the best of our knowledge, we, for the first time, systematically varied the Na content in the BEA zeolite prior to Cu impregnation. Intriguingly, we found a trade-off between the cold-start test (CST) activity (a simplified trap test for simulated HC emissions) and hydrothermal stability of the Cu-impregnated BEA zeolites. Specifically, increasing Na content decreased the CST performance monotonically, whereas it increased the hydrothermal stability. The decreased CST performance could be attributed to the less formation of the active Cu species (both Cu cations inside for preferred HC adsorption and CuO particles outside for facile HC oxidation). In addition, the improved hydrothermal stability benefited from dual features: Na+ ions could alleviate the zeolite structural collapse/damage during hydrothermal treatment (HT) at 800 °C by reducing the amount of most easily hydrolyzed Si-O(H)-Al bonds and avoid the formation of large CuO particles, which are known to destroy the zeolite structure during HT. As a net, we revealed that the Cu-impregnated BEA zeolite with an optimal Na/Al ratio of ca. 0.7 was key to achieving marked CST efficiencies in the HT state (22 %) in contrast to the H-form-based counterpart that exhibited extremely poor performance (i.e., nil).

Osinskaya subformation of the Usolsky formation of the Lower Cambrian of the central and southern parts of the Nepa-Botuoba anteclise: structure, formation conditions and biostratigraphical characteristics

Relevance. Geological prospecting carried out recently throughout the Lena-Tunguska oil-and-gas province makes studies of carbonates of the Osinskaya subformation particularly relevant, as they make it possible to establish the patterns of hydrocarbon trap formation. Aim. To present the results of the lithological and facial, biostratigraphic and petrophysical studies of the Osinskaya subformation in the southern and central part of the Nepa-Botuoba anteclise. Objects. Carbonate rocks of the middle Osinskaya subformation of the Usolskiy Formation of the Lower Cambrian Tommotian Stage, studied from well cores. Methods. GIS complex, detailed lithological and sedimentological description of the core, sequential stratigraphic analysis, petrographic analysis of 300 samples and examination of paleontological remains taken from the core; analysis. Results. Based on these studies, three sedimentation zones were identified, traced, and described for the first time: deep-water, marginal, and shallow-water. The deep-water zone is characterized by uncompensated sedimentation, the presence of single reefs, and confinement to depressions and troughs. It was flanked by an edge zone of carbonate platform associated with elevated thicknesses of the subformation and distribution of reefs over the area. It was followed by a shallow-water zone, represented by medium and reduced thicknesses of the Osinskaya subformation, its sediments are composed of carbonate grained and clayey rocks with small single reefs. The localized marginal zone of the extended carbonate platform agrees with the previously identified Chambinsko-Altybsko-Mirninskaya and Verkhnetokhomsko-Katsko-Pilyudinskaya zones of distribution of reef-like organogenic structures. On the basis of the studied wells, the structure of three formations according to the lithologic-facial profile was described. The paper introduces the authors’ variant of conducting the boundaries of the members. It was revealed that in the deep-water zone the prospects of searching for reservoir rocks are associated with single carbonate structures, in the marginal zone with area bioherms, and in the shallow-water zone with detrital deposits and shallow bioherms. The paleontological finds are shown to be confined to the selected sedimentation zones and beds. It was determined that algae diagnosed in the boudstones (autochthonous) were involved in the formation of the second and third strata, the edge zone of the carbonate platform. Archaeocyaths were diagnosed in detrital carbonate rocks of the second pack (allochthonous) in well no. 7 and autochthonous in boudstones of well no. 2X. Cribriciates were diagnosed in the boudstones of the third member (autochthonous). Archaeocyaths, cribriciates, namacalatusses, and calcareous algae studied from the cores of wells West Yaractinian no. 45, 361, Bolshetyrskaya no. 7, 3X, 2X, 4X, 5X, 6X were major edificators of Early Cambrian organogenic structures (biostromes, bioherms, bioherms massifs, reef formations).

Seismic interpretation of the Mero Field igneous rocks and its implications for pre- and post-salt CO2 generation – Santos Basin, offshore Brazil

Understanding igneous rock emplacement is crucial for deciphering any sedimentary basin's evolution. Its occurrence can be a determining factor for elements of the petroleum system, such as hydrocarbon generation, migration, trap formation, and reservoir quality. The high-impedance nature of igneous rocks in relation to their surrounding host rocks renders amplitude anomaly-based attributes sufficient for the identification of igneous bodies within siliciclastic sequences. However, this is not necessarily valid in pre-salt settings because of the high-impedance carbonates that make the impedance contrast subtle. Furthermore, if the emplacement characterization of the various magmatic pulses that occur in a given area over geological time were better evaluated, it would be possible to assess the gases (such as CO2) they produce with higher reliability. In this paper, the principal geometric and petroelastic characteristics of the igneous rocks of the Mero Field are described in detail in order to estimate the thermogenic production of CO2. Both manual and semi-automatic seismic interpretation were carried out to quantitatively and properly reduce the uncertainties inherent to the seismic mapping of these rocks. Thus, a 3D probabilistic igneous facies classification was performed based on a Bayesian inference using the P- and S-impedance well log data available and seismic elastic inversion volumes. These volumes of occurrence probability were useful for semi-automatically extracting maps and geobodies, which, along with conventional manual seismic interpretation, provided hypothetical volumetric scenarios for Mero igneous rocks and also for CO2 production. Five main intrusive features were recognized based on mainly in seismic geometries found in the Mero Field, two of them being Lower Cretaceous rift-related magmatism synchronous with the pre-salt reservoir deposition and the other three being related to the Santonian/Campanian magmatism. The analyzed data suggests that deep intrusions were responsible for the installation of a multiple hydrothermal vent system in the Santos Basin. During pre-salt sedimentation in the Lower Cretaceous, the emplacement of tholeiitic sills, primarily in low-energy facies at structural depressions, may have played a significant role in the thermal alteration of the sedimentary framework and would have released a significant amount of CO2 into the atmosphere. It's possible that the reactivation and reuse of these older structures (i.e., sill-related hydrothermal vent complexes generated by tholeiitic intrusions) during alkaline Santonian/Campanian magmatism might have contributed further to the production of additional carbon dioxide, which would be trapped in pre-salt reservoirs in this instance.

Integrated analysis of source rock evaluation and basin modelling in the Abu Gharadig Basin, Western Desert, Egypt: Insights from pyrolysis data, burial history, and trap characteristics

Source rock evaluation and basin modelling play crucial roles in understanding hydrocarbon potential. In this study, pyrolysis data from 92 shale ditch samples were employed to assess the source rocks in the Abu Gharadig Basin (Western Desert, Egypt). The organic richness ranged from 0.53% to 4.1% by weight, indicating varying hydrocarbon‐generating capabilities. Specifically, kerogen types II and III exhibited the potential to generate hydrocarbons, ranging from fair to good oil sources. The burial history analysis provided insights into the sedimentation and subsidence rates during different geological periods. The Late Jurassic‐Early Cretaceous period witnessed modest rates of sedimentation and subsidence. In contrast, the Oligocene and Late Miocene periods experienced medium burial rates, while the Late Cretaceous‐Early Tertiary period exhibited high burial rates. Specific formations were examined in detail, with the Apollonia Formation standing out as a significant hydrocarbon reservoir. It entered the early oil window at approximately 17.87 Ma and the wet gas window at about 17.41 Ma in the ASSIL‐1X well. However, it didn't reach the GPAA‐4 well. The Abu Roash ‘D’ member also showed promise, entering the early oil window at 38.20 and 47.38 Ma, and the wet gas window at 37.40 and 43.64 Ma. Similarly, the Abu Roash ‘F’ member exhibited favourable hydrocarbon generation, entering the early oil window at 39.90 and 54.86 Ma, and the wet gas window at 39.70 and 51.62 Ma in both the ASSIL‐1X and GPAA‐4 wells. Based on the analysis, the Apollonia, Abu Roash ‘D’ and ‘F’ members were identified as source rocks, while the Kharita, ‘C’, ‘E’ and ‘G’ members were recognized as reservoir rocks. The Abu Roash Shale acted as an effective seal rock. The geological structure of the region revealed the presence of NW‐SE normal faults, forming a three‐way dip closure trap. This research substantially enhances our comprehension of the hydrocarbon system within this basin. It achieves this by thoroughly investigating source rock evaluation, basin modelling and delivering invaluable insights into the mechanisms that govern hydrocarbon generation, expulsion and trap age.

Trapping, hysteresis and Ostwald ripening in hydrogen storage: A pore-scale imaging study

Green hydrogen, produced from surplus electricity during peak production, can be injected into subsurface reservoirs and retrieved during high-demand periods. In this study, X-ray tomography was employed to examine hysteresis resulting from repeated hydrogen injection and withdrawal. An unsteady state experiment was performed to evaluate the distribution of hydrogen and brine after drainage and imbibition cycles: images of the pore-space configuration of fluids were taken immediately once injection had stopped and after waiting for a period of 16 h with no flow. A Bentheimer sandstone sample with a length of 60 mm and diameter of 12.8 mm was used, and hydrogen was injected at ambient temperature and a pore pressure of 1 MPa. The gas flow rate was decreased from 2 ml/min to 0.08 ml/min over three cycles of gas injection followed by water flooding, while the brine injection rate was kept constant. The results showed the presence of capillary pressure hysteresis and hydrogen migration through Ostwald ripening due to the diffusion of gas dissolved in the brine. These phenomena were characterized through analysis of interfacial curvature, area, connectivity and pore occupancy. The hydrogen tended to reside in the larger pore spaces, consistent with water-wet conditions. 16 h after flow had stopped, the hydrogen aggregated into larger ganglia with a single large connected ganglion dominating the volume. Moreover, the Euler characteristic decreased after 16 h, indicating an improvement in connectivity. The work implies that Ostwald ripening – mass transport of dissolved gas – leads to less hysteresis and better connectivity than would be assumed ignoring this effect, as done in assessments of hydrocarbon flow and trapping.

Evaluation of Carbonate Reservoir with Integration of Petrophysical Analysis and Seismic Impedance Inversion in Banggai Basin, Sulawesi

Banggai Basin is controlled by the collision between Banggai-Sula micro-continent and East Sulawesi ophiolite belt, forming a thrust-sheet anticline structure that has potential to trap hydrocarbon. The Siotu-1 well was drilled right into the thrust-sheet anticline structure targeting Miocene carbonate platform layer. The same structure has proven to be an oil trap at the Tiaka oilfield which is located adjacent to the Siotu-1 well. This study aims to evaluate the presence of hydrocarbon in the Siotu-1 well with characterization of the Miocene carbonate reservoir. It is carried out by integrating petrophysical analysis from the Siotu-1 well log data and 2D seismic impedance inversion of the Tarib-1 line. Five reservoir zones have shale content values range of 21.91-37.53%, effective porosity values range of 9.7-14.62%, water saturation values range of 88.5-98.27%, and permeability values range of 2.53-8.16 mD. The results of the porosity calculation are validated by the model of seismic inversion where the reservoir zone with an acoustic impedance in the range of 7600-13450 ((m/s)/(g/cc)) is a carbonate layer with fair to excellent porosity (10 to> 25%) and reservoir zone with acoustic impedance values range of 13450-16200 ((m/s)/(g/cc)) as carbonate layer with poor porosity (< 10%). The net pay zone in reservoir zone 4 with a thickness of 4.5 feet and a net-to-gross of 0.006 are shown as the lumping result. It is concluded that Miocene carbonate reservoir in the Siotu-1 well met the criteria as a good reservoir rock but insignificant of hydrocarbon potential for further development.

Impact of the Regional Pai-Khoi-Altai Strike-Slip Zone on the Localization of Hydrocarbon Fields in Pre-Jurassic Units of West Siberia

The paper presents the results of a geological interpretation using gravity, magnetic, and seismic data to understand the oil and gas potential of pre-Jurassic sedimentary intervals and basement in the central West Siberia basin. The 200 km long Pai-Khoi-Altai strike-slip zone was investigated. Reconstruction based on a data complex indicate the right-lateral kinematics of the principal strike-slip faults and possible fault inversion. The study evaluated the spatial and genetic relationship between the conditions for hydrocarbon trap development and the strike-slip fault systems, such as “flower structures”. Strike-slip geometry and kinematics are confirmed based on 2D and 3D seismic data. Geological and geophysical criteria are used to forecast localization of hydrocarbon fields. Predictive zones are elongated in several different directions and have a different distribution pattern in the blocks separated by principal strike-slip faults, confirming its significance as a controlling factor for the hydrocarbon potential of the region’s structures.

3D structural modeling using seismic data and well logs for Khatatba reservoir in Matruh-Shushan Basin, North Western Desert, Egypt

Middle Jurassic reservoirs present challenges in the northern segment of the Western Desert due to geometric uncertainties arising from structural configurations, lateral facies variations, diverse lithologies, and heterogeneous reservoir quality. Consequently, this study employed an intricate approach, constructing detailed 3D geostatic models by amalgamating diverse datasets, including 2D seismic sections and digital well-logs. The focus of these 3D models was on the Khatatba Formation (Upper-Safa Member, Kabrit Member, and Lower-Safa Member) in Matruh—Shushan Basin in the North Western Desert. The objectives encompassed assessing hydrocarbon potential, precisely estimating reserves, formulating development and exploration strategies, and identifying prospective drilling locations. The resultant structural model revealed a compartmentalized region marked by major and minor NE–SW trending normal faults, establishing structurally advantageous locations for hydrocarbon trapping within the study area. Petrophysical analyses highlighted the promising potential of the Upper-Safa Member as a reservoir, featuring porosity values ranging from 10 to 18%, peaking in the northeast sector, volume of shale (Vsh) between 15 and 24%, water saturation (Sw) spanning from 18 to 53%, and increased sand thickness towards the eastern section. Similarly, the Lower-Safa Member demonstrated favorable reservoir attributes, including porosity values ranging from 10 to 16%, with higher values in the southeastern part, Vsh between 17 and 28%, and Sw varying from 15 to 47%. The study findings underscored the hydrocarbon potential in the northeast block of the study area for the Middle Jurassic Khatatba Formation. These insights contribute valuable information for decision-making in exploration and production endeavors within the basin.

Measurements of volatile organic compounds in ambient air by gas-chromatography and real-time Vocus PTR-TOF-MS: calibrations, instrument background corrections, and introducing a PTR Data Toolkit

Abstract. Volatile organic compound (VOC) emissions and subsequent oxidation contribute to the formation of secondary pollutants and poor air quality in general. As more VOCs at lower mixing ratios have become the target of air quality investigations, their quantification has been aided by technological advancements in proton-transfer-reaction time-of-flight mass spectrometry (PTR-TOF-MS). However, such quantification requires appropriate instrument background measurements and calibrations, particularly for VOCs without calibration standards. This study utilized a Vocus PTR-TOF-MS coupled with a gas chromatograph for real-time and speciated measurements of ambient VOCs in Boulder, Colorado, during spring 2021. The aim of these measurements was to understand and characterize instrument response and temporal variability as to inform the quantification of a broader range of detected VOCs. Fast, frequent calibrations were made every 2 h in addition to daily multipoint calibrations. Sensitivities derived from the fast calibrations were 5 ± 6 % (average and 1 standard deviation) lower than those derived from the multipoint calibrations due to an offset between the calibrations and instrument background measurement. This offset was caused, in part, by incomplete mixing of the standard with diluent. These fast calibrations were used in place of a normalization correction to account for variability in instrument response and accounted for non-constant reactor conditions caused by a gradual obstruction of the sample inlet. One symptom of these non-constant conditions was a trend in fragmentation, although the greatest observed variability was 6 % (1 relative standard deviation) for isoprene. A PTR Data Toolkit (PTR-DT) was developed to assess instrument performance and rapidly estimate the sensitivities of VOCs which could not be directly calibrated on the timescale of the fast calibrations using the measured sensitivities of standards, molecular properties, and simple reaction kinetics. Through this toolkit, the standards' sensitivities were recreated within 1 ± 8 % of the measured values. Three clean-air sources were compared: a hydrocarbon trap, zero-grade air and ultra-high purity nitrogen, and a catalytic zero-air generator. The catalytic zero-air generator yielded the lowest instrument background signals for the majority of ions, followed by the hydrocarbon trap. Depending on the ionization efficiency, product ion fragmentation, ion transmission, and instrument background, standards' limits of detection (5 s measurement integration) derived from the catalytic zero-air generator and the fast calibration sensitivities ranged from 2 ppbv (methanol) to 1 pptv (decamethylcyclopentasiloxane; D5 siloxane) with most standards having detection limits below 20 pptv. Finally, applications of measurements with low detection limits are considered for a few low-signal species including sub-parts-per-trillion by volume (pptv) enhancements of icosanal (and isomers; 1 min average) in a plume of cooking emissions, and sub-parts-per-trillion by volume enhancements in dimethyl disulfide in plumes containing other organosulfur compounds. Additionally, chromatograms of hexamethylcyclotrisiloxane, octamethylcyclotetrasiloxane, and decamethylcyclopentasiloxane (D3, D4, and D5 siloxanes, respectively), combined with high sensitivity, suggest that online measurements can reasonably be associated with the individual isomers.

Adsorption and desorption properties of toluene on an Ni-encapsulated Beta zeolite catalyst

Hydrocarbon trap (HCT) catalysts are promising automotive catalysts for purifying hydrocarbons in exhaust gas. Zeolites are suitable for use in these catalysts because of their high durability under hydrothermal conditions. Ni-encapsulated Beta zeolite (Ni@Beta) was obtained with Ni phyllosilicate as the Ni precursor. Ni@Beta exhibited higher toluene adsorption and desorption capabilities than those of Ni-impregnated Beta (Ni/Beta), and the Ni@Beta structure was stable after thermal aging at 900 °C. Moreover, Ni@Beta chemically adsorbed toluene after aging owing to the encapsulated Ni particles, which functioned as adsorption sites. In addition, the introduction of Ga into Ni@Beta improved the structural stability, and thus, the specific surface area was maintained at 80% after thermal treatment. Thus, this study provides an effective strategy for synthesizing HCT catalysts.

Three-Dimensional Integrated Geo-Static Modeling for Prospect Identification and Reserve Estimation in the Middle Miocene Multi-Reservoirs: A Case Study from Amal Field, Southern Gulf of Suez Province

Middle Miocene reservoirs in the southern part of the Gulf of Suez province are characterized by geometrical uncertainties due to their structural settings, lateral facies change, different lithologies, and diverse reservoir quality. Therefore, in this study, detailed 3D geo-static models were constructed by integrating multiple datasets, including 2D seismic sections and digital well-logs. The 3D models were constructed for the Belayim Formation (Hammam Faraun Member), Kareem Formation (Markha Member), and Rudies Formation (Upper Rudies Member) with detailed structuration, zonation, and layering for Amal Field in the southern Gulf of Suez province to assess the hydrocarbon potential, calculate accurate reserves, recommend development and exploration plans, and propose locations for future drilling. The resultant structural model exhibited a compartmentalized area of major and minor normal faults trending NW–SE, forming structurally high potential hydrocarbon trapping locations in the study area. The petrophysical models indicated the good potentiality of Hammam Faraun as a reservoir with porosity values of 15–23%, increasing towards the central part of the area, volume of shale (Vsh) of 21–31%, water saturation (Sw) of 34–49%, and sand thickness increasing toward the northeastern part of the area. The Markha Member was also interpreted as a good reservoir, with porosity values of 15–22%, increasing towards the southeastern part of the area, Vsh of 13–29%, Sw of 16–38%, and sandy facies accumulating in the central horst block. Upper Rudies exhibits good reservoir properties with porosity values of 16–23%, Vsh of 29–37%, Sw of 35–40%, and good sandy facies in the central horst block of the area. The study results showed hydrocarbon potential in the central horst block of the study area for the Middle Miocene multi-reservoirs.

New methods to reconstruct paleo-oil and gas compositions and P-T trapping conditions of hydrocarbon fluid inclusions in sedimentary basins

Accurate predictions of fluid composition and P-T trapping condition of hydrocarbon fluid inclusions (HFIs) is crucial to understand complex oil and gas charging history and accumulation mechanism. However, traditional P-T prediction methods are not enough powerful to get reliable results because of difficulty in direct composition measurement and great uncertainties in indirect composition prediction for single HFI. In this study, we collected 296 crude oil and 983 gas condensate fluids to develop new composition and trapping pressure (Pt) prediction models. Based on the measured fluid composition, saturation pressure (corresponding to homogenization pressure, Ph) and volume data, we firstly calibrate the Ph, the degree of bubble filling (Fv, at 20 °C) and isochores predictions for the measured fluids through matching saturation pressure and volume calibration and then established a standard fluid database with fluid composition, Ph, Fv and Pt. For the first time, a new hydrocarbon fluid composition prediction model was developed which is only function of Fv and homogenization temperature (Th) of HFIs. The new composition model allows directly predicting the entire fluid compositions from methane (C1) to heptane plus (C7+) fractions in HFI based on Fv and Th. Furthermore, we developed different Pt prediction models for varying fluid compositions and phase states of HFIs. For oil-bearing fluid inclusions which homogenize into liquid phase (OFIL) methane molar content is the only variable that is needed to predict Pt with a high degree of accuracy (8.2–12.3% for average absolute deviation, AAD). However, for gas condensate-bearing fluid inclusions (GCFI), more composition (C1–C7+) together with the physical property (molecular weight and specific gravity) of C7+ composition must be incorporated into the prediction model to obtain a better prediction accuracy of Pt. The new Pt prediction models give prediction accuracy of 11.2–17.6% (AAD) for GCFIL (homogenizing into liquid phase), and 15.9–22.8% (AAD) for GCFIG (homogenizing into gas phase). Our new composition and Pt prediction models can give the best and fastest predictions of hydrocarbon fluid composition and trapping condition and are of great significance for petroleum charging history reconstruction in sedimentary basins.

INTEGRATED ANALYSIS FOR ASSESSMENT OF DEEPER HYDROCARBON PLAY POTENTIAL IN REBAB-1, CENTRAL LUCONIA PROVINCE, SARAWAK

The basin history, thermal maturity, and hydrocarbon entrapments of Rebab-1 Well in Central Luconia have been relooked through the study of seismic, well log, and geochemical data to find new hydrocarbon potential in the deeper section of the well. The quality of source rocks in this area was based on assumptions, and hydrocarbon exploitation only occurs on shallow hydrocarbon plays making the potential for deeper plays difficult to ascertain. This study was conducted based on two 2D seismic lines, integrated with well lithological and stratigraphy data and geochemical data such as total organic carbon, pyrolysis, and vitrinite reflectance. Integration of these data was used to determine the deeper hydrocarbon play of Rebab-1 in Central Luconia Province. The seismic data were interpreted using Petrel software with validation from the report. Cross-plots from bulk geochemical analysis data were interpreted for the source rock's organic richness, kerogen quality, hydrocarbon-generating potentials, and thermal maturation levels. The results of seismic interpretations showed that extensional and compressional tectonics shaped the field of Rebab-1, with structures mainly trending to the NW-SE and NE-SW directions. Geochemical analysis showed that the total organic carbon content (TOC) of the samples analysed ranges between 0.06 and 2.98 wt.% indicating fair to very good source rocks producing mainly type II and mixed type II-III kerogen as the dominant kerogen. These types can generate mainly gas and mixed oil and gas accumulations upon attaining thermal maturation level. Also, Rebab-1 shows fair to very good hydrocarbon-generating potentials. The vitrinite reflectance (Ro) and Tmax results showed that the analysed samples are generally plotted in the immature, mature, and post-mature stages of oil generation but still within the gas generation window. Overall, source rocks from Rebab-1 can be said to have attained maturity at the youngest during depositions of Cycle III to older than that, and faulting and folding serves as hydrocarbon trap systems, indicative of potential in having deeper hydrocarbon plays in Rebab-1 well.

Emplacement dynamics of a complex thick mafic intrusion revealed by borehole image log facies analyses: Implications for fluid migration in the Parnaíba Basin petroleum system, Brazil

Sill intrusions may play a significant role in the development of petroleum systems in sedimentary basins by promoting maturation of source rocks, influencing fluid migration and acting as reservoirs, traps, and seals for hydrocarbon accumulations. Within this study, we present a novel approach to interpreting geophysical borehole data for a ca. 174 m thick sill from the Parnaíba Basin revealing new insights into both the emplacement mechanisms and impacts of the sill on hydrocarbon migration and trapping. High-resolution ultrasonic and microresistivity borehole image logs were integrated with conventional log data, petrography of eight side wall cores and total gas data recorded during drilling. The petrographic analysis revealed finer crystalline dolerite at the top and bottom layers of the sill while the upper central portion revealed coarser crystalline gabbroic facies, associated with anomalies in gamma ray, neutron porosity, sonic and geochemical log responses. From borehole image logs we interpreted key facies units including massive, fractured, cooling jointed and layered dolerite along with clear evidence for layers containing diverse inclusions interpreted as enclave structures. The integration and correlation of these data with analogue studies allowed the interpretation of gradational cooling with magmatic differentiation, partially melted host rock linked to sulphide production and organic matter maturation, mafic microgranular enclaves related to mingling processes of magma recharge, banding layers related to cumulate zones, and intense cooling fractures in the central sill body. An interval of ca. 44 m at the top of the sill with notably less jointing appears to be responsible for sealing the gas underneath, whilst the fractured central portion of the sill has enabled gas migration evidenced by increased gas signatures. In addition, this work also reveals for the first-time image log evidence for magma mingling and indications of assimilation and anatexis processes within the Parnaíba Basin. This study has important implications for improving the understanding of emplacement mechanisms of thick parallel layer intrusions and their implications for fluid flow in sedimentary basins worldwide.