Petroleum System Research Articles

Overview of the exploration potential of offshore Argentina – insight from new seismic interpretations

Argentina's offshore sedimentary basins cover a vast area on one of the widest continental margins on the planet, yet they remain underexplored today. Previous exploration drilling has failed to encounter commercial volumes of hydrocarbons, in part due to the poor seismic imaging of legacy 1960s–1990s 2D seismic data, and to the majority of wells being drilled on structural highs outside of the source rock kitchens. In this study, we reviewed 52 000 km of recently acquired (2017–2018) regional 2D long-offset seismic data with broadband pre-stack time (PSTM) and depth migration (PSDM) processing. We identified five major structural domains with hydrocarbon prospectivity on the Northern Margin of Argentina and four on the Southern Margin, and the presence of previously unseen structural and stratigraphic traps involving sequences assigned to proven regional source rocks and reservoirs in Permian, Jurassic and Cretaceous rocks. The source and reservoir rocks, petroleum systems, and play types present in the deepwater of the undrilled Argentina Basin represent a true frontier for hydrocarbon exploration. Pseudo relief attribute seismic displays and amplitude v. angle (AVA) analysis are demonstrated to be valuable tools in predicting the stratigraphy of the basins. A new framework for understanding the oil and gas prospectivity of the study area is presented.

GeoDIN - Geoscience-Based Deep Interaction Networks for Predicting Flow Dynamics in Reservoir Simulation Models

Summary Network graphs represent a general language for describing complex systems and a framework for knowledge discovery. Graph learning is a new concept with applications emerging in biomedicine, pharmacology, smart mobility, and physical reasoning. When applied to petroleum systems, such as reservoir models, graphs provide unique differentiators for the abstraction of reservoir connectivity to facilitate “reservoir-centric” machine learning (ML) applications. In this paper, we demonstrate, for the first time, the application of geoscience-based deep interaction networks (GeoDIN) to learn complex physics relationships from 3D reservoir models for fast and accurate prediction of subsurface spatio-temporal flow dynamics. We build the network graph with embedded subsurface and physics representations and train the ML model to “act like the reservoir simulator.” We use a simulation benchmark model for two-phase incompressible flow, with approximately 1.1 million grid size, one central injector, and four corner producers. Static 3D grid properties include porosity and permeability. We use full-physics simulation output to construct the interaction network (IN) graph, where graph nodes objects (nodes) represent reservoir grid cells. We embed the feature vector combining pore, oil and water volumes, and pressure and relative permeability. The graph objects representing wells are connected with well completion factors. The producing wells have embedded oil and water production rates, while the objects representing injecting wells have embedded water injection rates. We represent graph relations (edges) with bidirectional transmissibility of the source cell. To preprocess the data for ML, we scale the graph object attributes using “min-max” normalization and we normalize the graph relation attributes using Box-Cox transformation. We train the GeoDIN framework to predict oil and water saturation dynamics in space and time. When benchmarked with full-physics simulation, the INs ran on two V100 graphics processing units and substantially accelerated the prediction phase compared to the physics-based simulator running on 70 Intel Xeon E5 CPU cores. On average, the error in GeoDIN predicted spatio-temporal distribution of oil saturation remains within 5% of full-physics simulation for 90% of model grid cells, while the error in water saturation remains within 2.5% of full-physics simulation. The spatio-temporal propagation of pressure is more sensitive to local embeddings of INs, which communicate on node-to-node information transfer. This results in a larger prediction error of the GeoDIN model when benchmarked to full-physics simulation. On average, the error distribution suggests that the great majority (90 to 95%) of grid cells fall within 10 to 30% error bound relative to full-physics simulation. The presented GeoDIN approach to network learning carries a game-changing potential for the prediction of subsurface flow dynamics. As the way forward, we will investigate the implementation of graph neural networks with automated feature learning, generalization, and scaleup.

Geneses, Sources and Accumulation Process of Natural Gases in the Hinterland of the Junggar Basin

The Junggar Basin is rich in natural gas resources, but it has hardly been explored, with the proven rate being less than 9.0%. Although the hinterland of the Junggar Basin has a favorable condition for natural gas accumulation, the complex gas sources cause great trouble in the selection of zones and belts for exploration. Based on the molecular composition and stable carbon and hydrogen isotope data of 95 natural gas samples from 72 wells in this area, combined with the characteristics of structural evolution history, burial history, hydrocarbon generation and expulsion history, and fluid inclusions, this paper clarified the geneses and sources of natural gas, identified the secondary alteration of natural gas, and restored the process of natural gas accumulation. Natural gas in the hinterland was divided into four types: Type I was oil-type gas from the Lower Permian Fengcheng Formation; Type II was coal-type gas derived from the Carboniferous source rock; Type III was the mixture of Type I and II gases, which constituted the major fraction of natural gases in the hinterland; and Type IV that referred to secondary microbial gas formed by the biodegradation of crude oil. During the Late Cretaceous, the Carboniferous and Fengcheng source rocks entered the gas generation peak and a series of natural gas reservoirs were formed. However, affected by the later tectonic movements, some gas reservoirs were damaged or adjusted, and natural gas leakage and biodegradation occurred. This study has shifted the focus of natural gas exploration in the study area from the petroleum system associated with the Middle Permian source rocks to that with the Lower Permian and Carboniferous source rocks, which is of great significance for natural gas exploration in the Junggar Basin. Further, it provides an example to identify the geneses and sources of natural gas under complex conditions based on integrated geological and geochemical assessments.

Assessing Impacts on Pressure Stabilization and Leasing Acreage for CO2 Storage Utilizing Oil Migration Concepts

Favorable geological storage for CO2 has long been pictured as large anticlines with thick sandstones, similar to oil reservoirs in the petroleum system. Unlike oil, however, stored CO2 does not need to be recoverable, which raises the possibility of using dissolution and residual trapping to augment the capacity of buoyant traps and tap more of the bulk rock volume. The work presented builds on that idea, asking the following question: If we inject CO2 down to a syncline – analogous to the carrier bed in the petroleum system – how would this injection mechanism impact storage capacity and plume shape, migration, and stabilization? To address this question, we built a reservoir model, based on seismic interpretation of Middle Miocene strata, offshore Galveston, Texas. 3-D seismic and well logs were used to characterize key intervals. Reservoirs chosen for modeling are progradational-aggradational sands with mud intercalation. They have a higher degree of heterogeneity than the more conventional reservoirs commonly targeted for CO2 storage. Modeling investigated how far the CO2 plume would migrate under two scenarios: (1) injecting CO2 at the base of the salt withdrawal basin (syncline scenario) and (2) injecting CO2 at the base of the structural closure, similar to a common injection well location for EOR purposes (base scenario). For each scenario, we separately simulated injection of 30 MT of CO2 and 60 MT of CO2 continuously for 30 years and observe the plume and pressure evolution for 100 years after the injection stops. The simulation shows that injecting the CO2 into a syncline limits the vertical migration of CO2, thus making synclinal injection more secure. In the syncline scenario, the geological layer around the injection point is more heterogeneous than the layer in the base scenario; thus, the CO2 tends to migrate laterally. Additionally, in the syncline scenario, the plume does not even reach the upper part of the anticline, allowing us to safely store an additional amount of CO2 into the reservoir. Moreover, the simulation also shows that in the syncline scenario, the times needed for the reservoir to reach its stabilized pressure after the end of injections are faster. To summarize, CO2 injection at the base of a syncline could provide additional storage, increase the safety of the project from the limited vertical plume migration, and expedite plume stabilization, which could result in the decrease of monitoring frequency as the project runs, thus lowering the operating cost of the project in the long run.

Machine-learning assisted interpretation: Integrated fault prediction and extraction case study from the Groningen gas field, Netherlands

Seismic fault detection using machine-learning techniques, in particular the convolution neural network (CNN), is becoming a widely accepted practice in the field of seismic interpretation. Machine-learning algorithms are trained to mimic the capabilities of an experienced interpreter by recognizing patterns within seismic data and classifying them. Regardless of the method of seismic fault detection, interpretation or extraction of 3D fault representations from edge evidence or fault probability volumes is routine. Extracted fault representations are important to the understanding of the subsurface geology and are a critical input to upstream workflows including structural framework definition, static reservoir and petroleum system modeling, and well planning and derisking activities. Efforts to automate the detection and extraction of geologic features from seismic data have evolved in line with advances in computer algorithms, hardware, and machine-learning techniques. We have developed an assisted fault interpretation workflow for seismic fault detection and extraction, demonstrated through a case study from the Groningen gas field of the Upper Permian, Dutch Rotliegend; a heavily faulted, subsalt gas field located onshore, northeast Netherlands. Supervised using interpreter-led labeling, we apply a 2D multi-CNN to detect faults within a 3D prestack depth migrated seismic data set. After prediction, we apply a geometric evaluation of predicted faults, using a principal component analysis to produce geometric attribute representations (strike azimuth and planarity) of the fault prediction. Strike azimuth and planarity attributes are used to validate and automatically extract consistent 3D fault geometries, providing geologic context to the interpreter and input to dependent workflows more efficiently.

On the determination of oil charge history and the practical application of molecular maturity markers

Determining the thermal maturity and the charge history of crude oil to any reservoir, has key implications for understanding petroleum generation, accumulation history and hence identification of exploration potential. In this paper we combine studies of several source rock sequences and associated crude oils using quantitative component concentration data in addition to traditional molecular marker ratio parameter approaches. The case history studies include examination of organic-rich sapropelic marine source rocks from the Second White Speckled Shale Formation (2 WS Fm.), in the Western Canada Sedimentary Basin and the upper Jurassic Draupne Fm. in the North Sea and their related oils. Each molecular component in the petroleum has a unique concentration evolution curve during source rock maturation, in which n-alkanes, light aromatic hydrocarbons and diamondoid hydrocarbons increase in concentration with increasing maturity, while biomarkers decrease in concentration with maturity. This maturity dependent concentration variation plus the ubiquitous mixing of multiple oils in the reservoir is a key process that complicates the direct application of qualitative molecular marker ratio approaches to analysis of petroleum systems. We suggest an alternative maturity assessment approach using maturation calibrated curves of absolute concentrations of biomarkers and other alkanes in petroleum, coupled with selected aromatic hydrocarbon ratios to track the maturity/petroleum mass fraction relationships for a reservoired oil mixture in a more complex but realistic manner. Isoprenoid alkanes show less variation in concentration with maturity than other components and may be used as an internal reference point for mass fraction maturity and charge history assessment. Using component concentration data normalized to the concentration of the isoprenoid alkanes and calibrated using source rock analyses at different maturity levels from a single petroleum system (2WS), a simple mass balance model was constructed that allowed aggregate concentration data to be calculated for any mixture of oils produced in a prescribed oil charge history. In principle any charge history can be simulated using this approach and comparing the modelled and actual quantitative compositional profiles of crude oils allows differentiation of the more plausible and implausible oil charge histories for that particular reservoir. Clearly considerable refinement of this approach is needed but it appears that such a procedure has the potential, if developed further, to be a useful addition to the arsenal of petroleum geochemists and basin modelers. Knowing what a typical complete charge mass fraction maturity profile would look like for a given source rock type, enables the estimation of missing charge in the basin, allows the detection of complex multi-history charge scenarios, and provides a much more robust and complete data set for calibration of basin model charge history assessments. It also, with further development may be integrated into stochastic basin modelling approaches to study petroleum systems.

Miocene coals in the Hanoi Trough, onshore northern Vietnam: Depositional environment, vegetation, maturity, and source rock quality

The Hanoi Trough in northern Vietnam forms the landward extension of the large Song Hong Basin in the South China Sea. Several gas and condensate discoveries have been made in the offshore part while exploration in the Hanoi Trough has been less successful. Encountered hydrocarbons suggest a terrigenous source rock, the most likely candidate being Miocene coals. The composition of these is poorly documented in the public domain, but in the Hanoi Trough with a thinner Cenozoic succession numerous Miocene coal beds have been penetrated by several wells. The current study examines by organic petrography, geochemistry, and sedimentology the depositional environment, paleo-vegetation, thermal maturity and source rock potential of Miocene coal samples from two about 1000 m fully cored wells in the Hanoi Trough. The sedimentological facies, dinoflagellate cyst content and pyrite nodules suggest the coals were formed in coastal mires, in particular the younger section, testifying to an overall relative sea-level rise in the Miocene. This is supported by abundant framboidal pyrite and high TS contents in the coals. Dominance of huminite in all samples suggests water-logged mire conditions while abundant funginite and high concentrations of hopanes indicate high bacterial and fungal activity. Reduced fluorescence, oxidation rims, and elevated reflectance of resinite in a sample with concentrations of liptinite composed of resinite, cutinite, suberinite, sporinite and liptodetrinite might suggest the liptinite-enrichment was the result of degradational removal of less resistant organic matter. Biomarkers indicate the mire vegetation consisted of gymnosperms related to Podocapaceae or Cupressaceae, and perhaps Pinaceae. Presence of angiosperms is indicated by oleanane and aromatic oleananes, lupanes and ursanes. An unknown diterpane derived from Araucaria nemorosa (conifer in the Araucariaceae family) and/or Araucaria cunninghamii (pine) may be the first occurrence in a geological sample. The coals are of lignite to sub-bituminous A rank and are thermally immature with regard to hydrocarbon generation. They are today not at maximum burial depth due to c. 480–1450 m of Miocene uplift before reburial in Plio-Pleistocene time. HImax values around 200 mg HC/g TOC reveal the coals primarily are gas-prone, but exsudatinite in cleats in huminite and cell lumens in funginite is evidence for in situ generation from labile macerals. Oil droplets in cleats/cracks suggest migration of liquid hydrocarbons from deeper buried source rocks and are indicative of a working petroleum system in the Hanoi Trough.

Anabar–Lena Composite Tectono-Sedimentary Element, northern East Siberia

Abstract The Anabar–Lena Composite Tectono-Sedimentary Element (AL CTSE) is located in northern East Siberia extending for c. 700 km along the Laptev Sea coast between the Khatanga Bay and Lena River delta. The AL CTSE consists of rocks from the Mesoproterozoic to Late Cretaceous in age with the total thickness reaching 14 km. It evolved through the following tectonic settings: (1) Meso-Early Neoproterozoic intracratonic basin; (2) Ediacaran–Early Devonian passive margin; (3) Middle Devonian–Early Carboniferous rift; (4) late Early Carboniferous–latest Jurassic passive margin; (5) Permian foreland basin; (6) Triassic to Jurassic continental platform basin; and (7) latest Jurassic–earliest Late Cretaceous foreland basin. Proterozoic and lower–middle Paleozoic successions are composed mainly of carbonate rocks, while siliciclastic rocks dominate upper Paleozoic and Mesozoic sections. Several petroleum systems are assumed in the AL CTSE. Permian source rocks and Triassic sandstone reservoirs are the most important play elements. The presence of several mature source rock units and abundant oil and gas shows (both in wells and in outcrops), including the giant Olenek Bitumen Field, suggests that further exploration in this area may result in economic discoveries.

Palaeoenvironments Of The Permian-Cretaceous Sediments Of The Bintuni Bay, Papua

This paper presents a part of the result of Lemigas in-house research entitled Paleogeography and Hydrocarbon Potentiality of the pre-Tertiary Sediment of the Bintuni Basin, Papua, which is financially supported by the Government through a project so called DIPA 2009. In addition, this paper specifically discusses a palaeoenvironment of the Late Permian-Cretaceous sediment of the Bintuni Bay based on biostratigraphy. Data used in this paper is mostly secondary data obtained from National Data Center and an oil company which is therefore, classified as a confidential information. Paleoenvironment appeared in a non-marine setting during Permian-Triassic to form Ainim Formation in which, shale of this formation acts as a primary sourcerock for the studied area. Early Jurassic is characterised by a non-deposition, whilst Middle Jurassic is indicated by the occurrence of non-marine environment to deposit fluvial sandstone of the Lower Kembelangan Formation which is considered to be a main reservoir. Subsequently, environment shifted to the marine setting where deep marine shale occurred to form caprock. Mean while, the Early Cretaceous sediment disappears from the studied area suggesting massive erosion. Finally, depositional environment took place in the marine setting during the Late Cretaceous resulting in the formation of deep marine shale of Jass Formation which may contribute as a caprock in the element of petroleum system

Simulating the stratigraphy of meandering channels and point bars of Cretaceous system using spectral decomposition tool, Southwest Pakistan: Implications for petroleum exploration

Fluvial channels (FC) and point bars sandstone (PDs) sedimentary fills form primary brilliant stratigraphic petroleum systems within the transgressive system tract (TST). They are developed during the rapid rise and subsequent standstill of sea-level, which fills the reservoirs with FC and PD. These petroleum systems are ultra-thin-bedded (UTB) due to the very small vertical thickness of TST within the complete depositional sequences. Hence, they create hurdles in the prediction of lithology and porosity for these stratigraphic traps. The continuous wavelet transform (CWT) is the only sub-surface seismic imaging tool of spectral decomposition that can resolve the thin-beds of petroleum-bearing stratigraphic traps. This method removes the tuning effects of ambiguous lithology and fluids that masks the reservoir zones, and hence, generates false bright spots. This method decomposes the conventional seismic data into its constituent frequency components without fixing the vertical time window for the stratigraphic systems. These frequency components are further used for the prediction of lithology and porosity for resolving sub-surface depositional systems. Therefore, the CWT has delineated the fluvial sandstone facies, fractures connectivity, and architecture of the fluvial depositional system during the sea-level fluctuations. The 48-Hz has imaged the regional standstill of sea level, which have accumulated the porous sedimentary facies of coarse-grained FC andPDs. A very local sea-level rise was imaged in the eastern to the central part of this petroleum system. This sea-level fluctuation has implicated that there were minor cycles of transgressive sea-level, which has developed a pure stratigraphic play. The trace envelope attribute experienced a poor correlation coefficient with R2<0.2. The 48-Hz CWT experienced a correlation coefficient of R2>0.91 for FC and PDs. The conventional inverted reservoir simulation has imaged the low-frequency variance inside ~15-31% porous zones of FC and PDs. The 48-Hz volume has imaged the laterally continuous and hydrocarbon-bearing reservoirs with >25% porosity. 48-Hz CWT model also has imaged the coarse-grained FC of aggradational meandering channel stream, which were implicated to develop during stand-still of sea-level. These sandstone lenses were enclosed at the top by progradational shale facies of the highstand system tract (HST) and bottom and lateral by the shales of the TST. This workflow serves as an analogue within the SE-Asian sedimentary Basins and similar worldwide geological basins.

Prospect evaluation based on integrated petroleum system analysis: Block E case study, south-eastern edge of Precaspian Basin (Kazakhstan)

Generative potential and thermal maturity for Upper Palaeozoic source rocks from the south-eastern edge of Precaspian Basin were determined using Rock–Eval. A high hydrocarbon source rock generative potential and high degree of thermal maturity for the Lower Permian, Mid-Carboniferous strata have been revealed based on 39 rock samples. TOC values of 0.4–5.5% have been obtained for mature source rocks. Integrated geochemical analysis determined from Rock–Eval studies combined with 1D basin modelling was utilized in order to reconstruct thermal evolution for the Upper Palaeozoic source rocks. Calibrated 1D models for three wells had been constructed to understand petroleum system. For two deep exploration wells (Nur-1 and Tassym SE-1), which penetrated pre-salt strata at the depths of 5.7 and 7 km, respectively, the impact of salt diapirism on timing of maturation was modelled. Type II kerogen was used, which is based on previous palaeogeographic studies. The stratigraphic framework and major stages of geodynamic evolution were analysed. Salt-related structural traps in post-salt strata have been described based on 3D seismic data, and additional intra-salt sediment packages have been delineated. Discovered producing oil fields in the Upper Triassic and Jurassic–Cretaceous stratigraphic sections are mainly confined to the four-way dip structural closures above the steep flanks of salt structures. Based on burial and thermal modelling, the maturation and generation behaviour of kerogen Type II below salt-related minibasins and close to thick salt diapirs were inferred. For Lower Permian SR with type II kerogen, the generation peak (maturity over 50%) occurs in Middle to Late Jurassic. For predominantly carbonate and terrigenous-carbonate Mid-Carboniferous marine SR, generation peak occurs earlier below salt withdrawal minibasins. Implications for deeper hydrocarbon prospectivity were made for the study area, and methodology for evaluating hydrocarbon potential adopting 1D basin modelling technique and geochemical data is presented.

Non-equilibrium molecular dynamics simulation to evaluate the effect of confinement on fluid flow in silica nanopores

The flow of fluids in nano-confinement has applications in separations, water purification, medical systems and in the recovery of fluids in petroleum systems. It is believed that fluids do not obey continuum laws when flowing in nanopores (or in confinement). This paper attempts to shed light on various nano confinement effects such as fluid-wall interactions, pore size and molecular geometry, using molecular dynamic simulation. Water, hexane, and methanol flow behaviors were simulated for pore diameters ranging from 1 to 8 nm. In addition to the density analysis of the confined fluids, the fluid flows in saturated nanopores were simulated by the sectional flow method. Water and methanol molecules were completely stabilized in the 1 nm pore. Hexane molecules could not enter the 1 nm pore, due to geometric considerations. For the 2 – 8 nm pores, all fluids showed reduced flow rate compared to the Hagen–Poiseuille flow, due to an interfacial molecular layer stabilized at the pore surface. Flow reduction observed in these studies is contrary to significant flow enhancements observed for fluid flow in carbon nanotubes of similar dimensions. Water flow showed almost constant stick length for all the pore sizes. Methanol flow had the largest stick length. Hexane flow was reduced because of overcrowding of molecules at the pore surface. The effect of confinement diminished with an increase in pore diameter.

Siderite occurrence in petroleum systems and its potential as a hydrocarbon-migration proxy: A case study of the Catcher Area Development and the Bittern area, UK North Sea

We report a detailed magnetic study of Tertiary sandstone cores from the Bittern field, West Central Graben, and Catcher Area Development (CAD), West Central Shelf, UK North Sea that identified siderite as a potential magnetic proxy for the differentiation of vertical and lateral hydrocarbon migration. Magnetic hysteresis experiments revealed increased presence of paramagnetic minerals in the oil-stained sandstones of the fields compared to the nearby dry Tertiary (unstained) sandstone of offset wells. Within the oil-stained sandstones, the paramagnetic proportion is highly variant, with low and high paramagnetic sections present. Detailed experiments including thermomagnetometry between 10 K and 900 K and XRD analysis, combined with Mössbauer spectroscopy confirmed that this increase in paramagnetic response was primarily due to the formation of siderite. An increase in the quantity of paramagnetic clays and occasionally pyrite also contributed to the increased response. Siderite and iron sulphides have been interpreted to form during hydrocarbon migration and potentially oil biodegradation. We propose that hydrocarbon migration pathways may be indicated by the distribution of siderite. We argue that as hydrocarbons migrate vertically and the equilibrium partial pressure of CO2 with the environment reduces, essential HCO3− is produced which reacts with available Fe2+ to form siderite if all the other diagenetic requirements for its formation are met. The distribution of siderite and magnetic susceptibility values along the oil-stained layer provides a tool for the determination of the migration pathways in low sulphur hydrocarbon environments containing reactive iron.

Potential of ALOS-2 PALSAR-2 StripMap data for lithofacies identification and geological lineament mapping in vegetated fold-thrust belt of Nagaland, India

• Geological mapping of vegetation-covered NFTB is done with ALOS-2 SAR data. • Second order lithological variance could be discriminated by this process. • Meso-scaled geological lineaments has been mapped and analysed. In this study statics-based textural analysis GLCM (Grey Level Co-occurrence Matrix) of high resolution L band SAR data from ALOS-2 of JAXA has been used to discriminate between lithological facies of the fold-thrust belt of Nagaland, India. Sandstones, shales, siltstones and clays have been separated in the analysis. Importantly, the lithological facies with second-order compositional variance have been distinguished from each other. The study of 27 lithological pairs indicates a Transformed Divergence index greater than 1.7 except one pair which shows an index of 1.6. The average GLCM texture values of different stratigraphic units in VV and VH polarization shows appreciable differences. Coefficient of variation of the texture samples from each descriptor show uniform distribution around their mean. The mean has thus been used as a lithological index in this study. Further, the medium scaled geological lineaments have been extracted and mapped at 1: 25,000 scale. The Compass Edge Detector on the first Principal Component of full polarized ALOS-2 scene has been used for this purpose. Fracture network, outcrop length, density, and orientation have also been analyzed. The study is successful in rock characterization within vegetation-covered landscape, using L band SAR remote sensing. It may provide an important tool in geological mapping in inaccessible terrains with limited ground data control. The fracture map and its study can provide some useful insights about reservoir characterization and reduce exploration risk in this terrain that has a proven petroleum system.

Overview of the Late Jurassic Madbi-Sab'atayn petroleum system in the Marib Concession, northwestern Sab'atayn Basin (Yemen): hydrocarbon from source to trapping

Overview of the Late Jurassic Madbi-Sab'atayn petroleum system in the Marib Concession, northwestern Sab'atayn Basin (Yemen): hydrocarbon from source to trapping

Mature petroleum hydrocarbons contamination in surface and subsurface waters of Kızılırmak Graben (Central Anatolia, Turkey): Geochemical evidence for a working petroleum system associated with a possible salt diapir

Salt formations exist in Kızılırmak Graben (Central Anatolia, Turkey), which consists of volcano-sedimentary units, and it was stated in previous studies that these formations have a diapiric structure. The adjacent basin, Ayhan Basin, contains bituminous shale and operated coal deposits. For this reason, in this study, it is aimed to investigate the oil and gas potential of the Kızılırmak Graben by conducting TPH (Total Petroleum Hydrocarbons) analysis on the samples taken from natural cold-water resources by making use of the thought that hydrocarbon generation may come into existence from those units in the Ayhan basin. As a consequence of the analyses performed, hydrocarbons have been brought into the open in all the water samples. The organic geochemical methods have been used to find out the source of hydrocarbons determined in the water resources. The disclosed n-alkane hydrocarbons are the mature petroleum hydrocarbons derived from peat/coal type organic matter (Type III kerogen, gas-prone). These mature hydrocarbon-rich waters can be regarded as evidence for the availability of a working hydrocarbon system associated with possible salt diapir identified by using gravity and magnetic data obtained from the investigation area.

Hydrocarbon Potential of the South-Western Part of the Cauto Basin, Cuba

The “Assessment of the southwestern of the Cauto Basin and its oil and Gas possibilities in Cuba” was carried out with the objective of evaluating the southwestern part of the Cauto Basin in Cuba from the geological and geophysical point of view, with the southwestern of the Basin as a foundation of the petroleum system models. The method of investigation employed included interpretation of the seismic lines, the surface geology, the well logging data, gravimetric and magnetometrics data. The research was developed in three fundamental stages: I) Preliminary stage, II) Data processing and III) Interpretation of results/conclusions and recommendations. The characterization of sedimentary structures was assessed, and the evolution of the studied basin was also realized. Based on the result of this study, the origin of Cauto Basin can be linked to the geological event that occurred in the area towards the end of the Cretaceous era which involves complex sedimentary processes with associated collusions and extension of tectonic transcurrente. This leads to formation of Delta zones and important fans, which were the product of rapid sedimentation and slow subsidence. Furthermore, the result reveals that the studied interval can be described as a potential reservoir for being part of the fan and deltaic zone. There is evidence of the presence of hydrocarbon within the studied interval, but probing further depth has the potential of more discovery within the source rock since only the Tertiary reservoirs were evaluated.

Structural interpretation of 2D seismic reflection data of the Khabour Formation in the Upper West Euphrates, western Iraq

The seismic reflection method has a primary role in petroleum exploration. This research is a structural interpretation study of the 2D seismic reflection survey carried out in the Upper West Euphrates (Khan Al-Baghdadi area), which is located in the western part of Iraq, Al-Anbar governorate. The two objectives of this research are to interpret Base Akkas/Top Khabour reflector and to define potential hydrocarbon traps in the surveyed area. Based on the synthetic seismogram of Akk_3 well near the study area, the Akkas/Top Khabour reflector was identified on the seismic section. Also, the Silurian Akkas Hot_shale reflector was identified and followed up, which represents the source and seal rocks of the Paleozoic petroleum system in the Western Desert of Iraq. Time, velocity, depth, and isopach maps were drawn for Base Akkas/Top Khabour reflector and showed the presence of two anticline structures trending east-west and located on the west side of the study area. The first is termed as (A), represented by Tulul structure, and the second is termed as (B). The maps show the increase in time toward the eastern side of the study area. The general slope of the reflectors is toward the southeast of the study area, while the increase of the thickness of the Formation is gradual to the southwest as well as the northwest of the study area. The study area was affected by three transversal faults. Generally, the faults have northeast-southwest trends. The Ordovician Khabour sands are the primary reservoir in the study area. They are interpreted to be present throughout Akkas Field as gas/condensate accumulation located 100 km to the west of the study area.

Tectonics characterization of the salt influenced structures: Insights from a seismic data interpretation in the eastern part of the Persian Gulf, Iran

Salt tectonics can influence the petroleum systems via the development and distribution of ductile migration pathways through the structural and stratigraphic traps. In this study, the effects of base-salt relief on the development of salt décollement horizon and the salt-influenced structures were investigated in the eastern part of the Persian Gulf, NE of the Afro-Arabian Plate. For this purpose, data from hydrocarbon exploration wells and seismic lines of the region have been used. To set the position in a time of the main stratigraphic and acoustic markers, and to compare well and seismic data, the processing of synthetic seismogram and the conversion of logs in the time domain has been performed for the selected well.Interpretation of seismic sections revealed the occurrence of a NE-SW trending horst structure and development of a natural model of the salt tectonics on its overburden of the Oligocene to Miocene sedimentary layers. The presence of Oligo-Miocene saliferous beds as a décollement has provided suitable conditions for overburden sediments gravitational sliding and development of thin-skinned extension which started during the Miocene time and it was evolved up to the present time. This condition controlled the geometry of salt-influenced structures in the eastern parts of the Persian Gulf and resulted in the formation of special structural features namely hereafter as Curly Bracket Structures in the overburden.

GIS based integration of multi-spectral remote sensing and morphostructural analysis for delineating potential areas of hydrocarbon exploration in Western Vindhyan Basin, India

The Chambal Valley forms the western part of the Proterozoic Vindhyan Basin that has been less studied and poorly explored from the hydrocarbon perspective than its eastern counterpart—the Son Valley Vindhyans. In the present manuscript, attempts have been made to use remote sensing and GIS (geographic information system) based analysis to focus on the northern part of Chambal Valley to decipher its tectonics and structural configuration, its tectonic relation with the Son Valley Vindhyans, Bundelkhand Massif and Ganga Basin. This study also assumes significance as it attempts to delineate potential lead areas for hydrocarbon exploration in Chambal Valley. As part of the study, a detailed spectral analysis based on image data sets is carried out to identify areas of microseeps as proxies of potential hydrocarbon accumulations. Also, a neotectonics-based geomorphic analysis is carried out to delineate a fault network and geomorphic highs that act as aliases to subsurface faults and structural highs. The results are subsequently validated by available geophysical data and extensive fieldwork, and suggest four structural trends in the Chambal Valley as striking NE-SW, E-W, NW-SE and N–S, of which the NW-SE trend is the oldest, followed by the NE-SW, E-W and N–S trends. A GIS-based analysis of the E-W trends indicates that these are probably manifestations of the westward continuity of E-W-trending shear zones developed in Bundelkhand massif within the basement of the Chambal Valley. Further remote sensing studies of the shear zone network exposed in the Bundelkhand massif indicate the pattern to be replicated on a larger scale in the morphostructural fault layout in the adjacent Ganga Basin, implying these shear zones may be continuing in the basement of Ganga Basin and controlling structures developed later, and consequently the different petroleum system elements in the basin. A dip data based structural analysis of the Chambal Valley describes a regional synform attributed with an almost vertical NW-SE-trending axial trace. This axial trace may be in continuity with the NE-SW-trending synformal axis of the Son Valley with its trajectory sympathetic to the southern boundary of the Bundelkhand massif and the Central Indian Tectonic Zone (CITZ) – Aravalli Delhi Fold Belt (ADFB) geometry. Finally, based on the integration of the results of spectral and morphostructural analysis, a number of potential areas of hydrocarbon exploration are demarcated in the study area.