Hydrocarbon Exploration Research Articles

Appraisal of reservoir porosity using a machine learning approach: A study from the Eocene‐Miocene interval of Upper Assam Basin, NE, India

Porosity estimation is essential for the exploration of hydrocarbons in sedimentary basins, which are affected by several factors such as the burial depth, lithology changes, sedimentary environment and diagenetic degree. Hence, detailed understanding of reservoir porosity is essential for estimating potential economic reserves and developing an explored hydrocarbon field. The present study uses high‐quality three‐dimensional (3D) seismic reflection data to decipher the porous zones within the Eocene‐Oligocene‐Miocene intervals of the Upper Assam Basin. The coherency seismic attribute has brought out several fault‐bounded structures that control the reservoir geometry. Random forest‐based machine learning technique has been utilized for the porosity estimation within the formations of interest. It is observed that the north‐east (NE) parts of the targeted intervals are porous with varying porosity of 0.28–0.42. The Miocene period witnessed a high amount of sedimentation within the basin. Different structural highs and thicknesses are pronounced in the NE part of the study region. Thus, the Miocene intervals are favourable leads for the exploitation of hydrocarbons.

Linking the sedimentary cyclicity with mechanical and physical properties of limestone and marl rocks, Dam Formation, Eastern Saudi Arabia: Implications for hydrocarbon exploration and reservoir development

Linking the sedimentary cyclicity with mechanical and physical properties of limestone and marl rocks, Dam Formation, Eastern Saudi Arabia: Implications for hydrocarbon exploration and reservoir development

Regional Scale, Fault‐Related Fluid Circulation in the Ionian Zone of the External Hellenides Fold‐And‐Thrust Belt, Western Greece: Clues for Fluid Flow in Fractured Carbonate Reservoirs

AbstractWe combined field mapping, structural and microstructural analyses, stable‐clumped isotope geochemistry, and U‐Pb dating of calcite veins and syn‐tectonic slickenfibres, to assess the regional scale fault‐related fluid flow during the evolution of the External Hellenides fold‐and‐thrust belt. We show that fluid circulation during forebulge uplift was characterized by cold meteoric water‐derived fluids, from which calcite precipitated and sealed bed‐perpendicular joints. Fluid circulation during foreland flexuring and early layer‐parallel shortening was characterized by warm fluids buffered by the carbonate host rock, which circulated through normal faults and bed‐parallel veins. Mixing with meteoric‐derived fluids also occurred at this stage of tectonic evolution. Fluid circulation during the late stage of thrust wedge accretion and post‐orogenic extension at 1.6 ± 1 Ma was characterized by increasing dominance of cold meteoric water circulating in strike‐slip and normal faults. The ingress of meteoric‐derived fluids was controlled by throughgoing fault conduits, while host rock‐buffered fluids were confined in isolated structures such as minor faults and veins. We developed a conceptual model of fault‐related fluid circulation, which invokes a transition from an open fluid system during forebulge uplift, to a semi‐closed fluid system during foreland flexuring and early layer‐parallel shortening, and to an open system during late thrust wedge accretion and post‐orogenic extension. This type of fluid circulation may have impacted fluid migration/leakage, including hydrocarbons, into or outside potential reservoirs in the highly prospective Hellenides‐Albanides fold‐and‐thrust belt, a renovated frontier for hydrocarbon exploration in the Mediterranean area.

Quantitative identification of triassic top unconformity: vertical structure and its reservoir significance in the sanbian area of the ordos basin

The Triassic top unconformity in the Ordos Basin, which serves as a transfer station for hydrocarbon migration, has become a bottleneck for Mesozoic oil and gas exploration. Taking the Sanbian area as an example, based on core observations, petrophysical properties, and a weathering index analysis of five coring wells, a standard for the quantitative identification of the vertical structure of the unconformity is established using the optimal segmentation method and principal component analysis of conventional logging curves. The standard is then applied to 40 real wells, and 32 typical unconformity reservoirs are dissected. The results show that the reclassification of the unconformity surface corrects the 17.5% error in the geological stratification as an unconformity. On this basis, a quantitative identification standard for the structure of the unconformity is established via the principal component curve. The analysis of unconformity structure types applied to five paleogeomorphic units reveals that the slope mouth and slope develop three layers of structure, namely residual layer, weathered clay layer, and weathered leaching zone, while highlands, river valleys, and inter-river hills lack weathered clay layer. As an independent oil and gas-bearing layer, the unconformity has two types of reservoir-forming models. The first is the hydrocarbon accumulation in the Chang1–Chang2 member shielded by weathered clay layer in the slope mouth and slope. The second is hydrocarbon migrated from the residual layer to the local structural high part of the Yan 10–Yan 9 member in the slope mouth. The hydrocarbon in the unconformity is complementary to the upper Yan 10–Yan 9 member and the lower unweathered rock layer of Yanchang Formation. The results of this study are of great significance to the quantitative identification of unconformity structures in exploration wells without coring data in the study area, as well as to future hydrocarbon exploration in the Mesozoic strata.

The use of innovative method of p-s wave seismic reflection technology in hydrocarbons exploration

This study endeavor aims to provide a very detailed explanation of seismic reflection survey-based hydrocarbon exploration. The purpose of the research is to determine why some oil industry wells still remain dry after being drilled. Emphasis was placed on the potential application of innovative methods with the goal of developing a novel response to this trend. A more in-depth examination of the arguments for using seismic technology based on (p-s) waves rather than p-wave alone for hydrocarbon exploration is stressed in order to fully understand this approach. This clears the way for dealing with seismic abnormalities and pitfalls that could be contributing to the need to drill dry wells. According to drilling suggestions, the P-S wave was used in this study to achieve a spectacular result. The precise location of the gas-trapped in sandstone deposit is at coordinates (5250m, 2200–2400m). This indicates that there is a 200-meter-wide gas-promising zone here as well, so in order to recover the formation gas, drillers must proceed to a depth of 5250 meters starting between 2200 and 2400 meters below the profile's surface, ideally at 2300 meters. The precise location of the limestone's trapped gas formation is at coordinates (8750m, 600--900m). This indicates that the prospective zone for gas deposits is extended out by roughly 300m. Therefore, drilling must be done ideally at 750m on the surface and sidetrack about 150m both left and right to a depth of around 8750m (8.75km), in order to retrieve the reserve gas or trapped gas. Thess findings are crucial for a hydrocarbons exploration to be successful and reduce the likelihood of digging dry wells in the oil industry.

Reservoir characteristics and potential of a shallow-marine multi-level fan in the Miocene Huangliu Fm. within the DF1-1 gas field (Yinggehai Basin, S China)

Deep-marine fans receive much attention because of their high potential for hydrocarbon exploration. Shallow-marine fans are much rarer and less well investigated. Particularly the formation and reservoir distribution of shallow-marine multi-level submarine fans are still hardly understood. Integration of data from cores, well logs, 3D seismics, in combination with analyses of thin-sections, porosity and permeability of Member 1 of the Miocene Huangliu Formation in the DF1-1 Gas Field of the Yinggehai Basin (S China) has provided much new information on the characteristics, development, and hydrocarbon potential of the reservoirs in such a type of fan. The study indicates that the IIb Gas Level of this member is built of three 5th-order sequences. The fan consists of channels, levees, ‘overbank’ sand sheets, and pro-fan silt- and mudstones. The development of this fan was controlled mainly by alternating subcritical and supercritical gravity flows, sediments supply and relative sea-level fluctuations. The NW-SE running channels occur on three slightly different levels that form 3 zones with chutes-and-pools morphology, which results in a multi-level submarine fan with zones of different sand thickness. The sand content of the channels and sand sheets is commonly higher than 50%. The reservoir sands underwent intermediate compaction and show mainly primary intergranular pores with short contacts. The porosity is 13.7–19.5% and the permeability ranges from 3.2 to 14.2 mD. The best reservoirs are the sand sheets, followed by channel sediments. The various reservoirs are commonly not interconnected due to lithological and stratigraphic traps. A new reservoir distribution model of submarine fans could thus be developed, which will facilitate oil and gas exploration.

Azimuthal Prestack Seismic Anisotropic Inversion on a Deep and Tight Carbonate Reservoir From the North Potwar Basin of Pakistan

Summary Quantitative characterization of deep, tight, and heterogeneous reservoirs plays an important role in identifying hydrocarbon pathways for effective and optimal reservoir field development. In this case study, we used an azimuthal prestack seismic anisotropic inversion approach to estimate attributes of horizontal transverse isotropy (HTI) caused by a set of vertical fractures, oriented cracks, and stress. Anisotropic inversion facilitated the conversion of interface properties to the corresponding layer-based properties, which led to the quantitative interpretation of reservoir properties related to azimuthal variation in seismic amplitudes. To estimate the anisotropy magnitude and the direction of the isotropy axis in HTI media, elastic properties (P-impedance and Vp/Vs) obtained from prestack seismic inversion (using six azimuth × four angle stack) served as inputs. The isotropic low-frequency model (LFM) is used as the foundation of the inversion for all azimuths, and the anisotropy effects are later added by updating the model along the azimuths. The direction of the isotropy plane resulting from the anisotropic inversion is determined by using the maximum horizontal stress as a prior constraint, which eliminates any inherent uncertainty. The workflow used effectively characterized the orientation and density of fractures from the recently discovered oilfield reservoirs of the Paleocene (Lockhart) formation located in Pakistan’s north Potwar Basin. It also helped improve the prediction accuracy for fractures in the study area. According to the observations (fractures) from the exploratory drilled well (D1) in the tight carbonate (Lockhart) reservoir, a significant amount of anisotropy magnitude is observed. This provides the basis for hydrocarbon exploration, field development, and reliable drilling decisions.

Astronomically forced cycles in Lower Carboniferous Luzhai Formation shales, Guizhong Depression, South China

Early Carboniferous Luzhai Formation developed continuous and thick shales, which is a critical succession for hydrocarbon exploration and production in southern China. However, no high-resolution stratigraphic sequence framework or cyclostratigraphic studies on early Carboniferous (Tournaisian Stage) are available for this organic-rich shale formation. In this research, Milankovitch cycle evidence has been reported in two boreholes of Luzhai Formation in Guizhong Depression. Natural gamma-ray logging data allowed the establishment of a ∼5.9-Myr floating astronomical timescale (FATS) based on stable long eccentricity (405-kyr) cycles in Luzhai Formation. We anchored FATS to Devonian and Carboniferous boundary age (359.3 ± 0.4 Ma), and an absolute timescale for intervals of 359.3 to 353.4 Ma was developed. Correlation coefficient (COCO), evolutionary COCO, and evolutionary TimeOpt method (eTimeOpt) were employed for quantitatively fit observed stratigraphic cycles to astronomical cycles for providing possible range of sedimentation rates. Sedimentary noise model was adopted for detecting orbital forcing-controlled high-resolution sea-level changes which were correlated to ∼1.2-Myr obliquity amplitude modulation (AM) cycles. Sedimentary noise models (autocorrelation coefficient analysis, ρ1, and dynamic noise after orbital tuning analysis, DYNOT) revealed a correlation between obliquity AM cycle (∼1.2-Myr) and sea level changes in early Carboniferous Luzhai Formation. The ∼1.2-Myr obliquity AM was the main driver of third-order sequence development, the 3rd-order sequence boundaries were related to maximum values of DYNOT median curve and minima values of ∼1.2-Myr amplitude modulation (AM) curve.

Direct hydrocarbon indicator analysis to predict reservoir in Deepwater Krishna-Godavari basin: a case study

The amplitude Variations with Offset (AVO) technique is extensively used in hydrocarbon exploration and production for de-risking of the prospect before drilling. The interpretation of AVO results brings more confidence in the presence or absence of hydrocarbon. The AVO and Direct Hydrocarbon Indicator (DHI) analysis have their own inherent limitations. Therefore, to ensure the presence of true AVO in seismic, other attribute supports are crucial. The present prospect in this study was deposited as a channel-levee complex in the shelf-slope of the Krishna-Godavari basin. There is evidence of false AVO within this complex and thus additional attributes were used in this study to support the AVO analysis. The conventional AVO analysis shows the presence of Class-III AVO for a probable reservoir in seismic. However, it is unable to ensure the presence of hydrocarbon in the stacked reservoir unit. The spectral AVO technique was used to check AVO response at low frequencies for laminated and stacked reservoir units. Additionally, seismic attenuation and dispersion attribute studies were incorporated into the de-risking analysis. The drill result showed two distinct reservoir intervals in this prospect, which validated the predrill interpretation. This integrated approach added significant value in de-risking the prospect using AVO and other seismic attributes in complex geologic setups.

Concurrent influence of geological parameters on the integrated nano-pore structure and discretized pore families of the petroliferous Cambay shale assessed through multivariate dependence measure

Heterogeneous nanopore structure and distribution regulate the gas trapping, desorption kinetics, and diffusion in shale matrices. In shale, pores range from continuous micro- and mesopore size distributions, varying with organic (total organic matter-TOC) and inorganic constituents (clay content, Fe-bearing minerals, quartz, etc.). Previous research only showed a linear relationship of pore parameters with these intrinsic properties of shale, which limits our understanding of the concurrent influence of multiple intrinsic rock properties. As a result, in this work, we established multivariate dependency of nanopore structure, distribution, and complexity (from low-pressure N2 and CO2 sorption and small-angle scattering; SAXS/MSANS) in the previously little-studied Cambay shales and provided a better tool (partial least square regression) for analyzing the simultaneous effect of intrinsic shale properties on multiply connected pore-parameters. Furthermore, we discretized continuous pore-size distribution into individual pore families using deconvolution to understand the pore space better. Additionally, predicted shale formation environment in terms of deposition probability (P+) and dissolution probability (P−) using a dynamic model of the fractal interface by precipitation and dissolution. Our findings indicate that the Cambay shales have a high potential for future hydrocarbon exploration (S2: 2.42–12.04 mg HC/g rock), “very good” (2-4 wt.%) to “excellent” (>4 wt.%) TOC content, and thermally mature type II–III admixed and type III kerogen. Deconvolution of the micro- and mesopore size distributions reveals that pore width (w) ranges ∼15.30–35 nm occupies greater than 50% of the total pore volume, and its pore volume increases with the presence of quartz, Fe-bearing minerals, and clay content. However, pores with w∼ 3.60–15.30 nm increase exclusively with TOC. In the micro- and early mesopore region, pore volume decreases with TOC from w∼ 0.30–0.75 nm and increases with TOC from w∼ 0.75–3.60 nm. Furthermore, TOC in shale increases the specific surface area and pore volume (micro-, meso-, and total pores), enhancing both sorption and free gas storage capacities. Cambay shales were likely deposited in three distinct environments, with precipitation probability (P+) values of 1, 0.7–0.8, and 0.5, as revealed by a fractal dimension (Ds) analysis of multiple samples.

Full-waveform inversion by model extension: Practical applications

Producing reliable acoustic subsurface velocity models still remains the main bottleneck of the oil and gas industry’s traditional imaging sequence. In complex geologic settings, the output of conventional ray-based or wave-equation-based tomographic methods may not be sufficiently accurate for full-waveform inversion (FWI) to converge to a geologically satisfactory earth model. We create a new method referred to as full-waveform inversion by model extension (FWIME) in which a wave-equation migration velocity analysis (WEMVA) technique is efficiently paired with a modified version of FWI. We find that our method is more powerful than applying WEMVA and FWI sequentially, and that it can converge to accurate solutions without the use of a good initial guess or low-frequency energy. We determine FWIME’s potential on five realistic and challenging numerical examples that simulate complex geologic scenarios often encountered in hydrocarbon exploration. We guide the reader step by step throughout the optimization process. We find that our method can simultaneously invert all wave types with the same simple mechanism and without the need for a user-intensive hyperparameter tuning process. In an open-source online repository, we provide our C++/compute unified device architecture (CUDA) numerical implementation accelerated with graphics processing units, encapsulated in a Python interface. All the numerical examples developed are accessible through Python notebooks and fully reproducible.

Connecting the Iberian Range with the Basque-Cantabrian Basin: The structure of the Sierra de Atapuerca (Spain)

We present a structural model of the Sierra de Atapuerca which constitutes the transition zone between the Iberian Range and the southwestern Basque Cantabrian Basin, NW Spain, where the Sierra de Atapuerca is located. The interpretation integrates both subsurface well and seismic hydrocarbon exploration data with surface geology. According to our interpretation, the Sierra de Atapuerca consists of a pop-up basement involved structure and is part of a NW-SE transpressive strike-slip band formed by high-angle faults segmented by transfer faults with a NE-SW direction. All this strike-slip alignment is located in the northern area of the Duero Basin and forms the footwall of the Duero North Thrust, which has transported the Folded Band and the Burgalesa Platform over this area thanks to a Triassic detachment, in a thin-skinned tectonics context. The Rojas and NW Demanda tectonic arcs represent the structural terminations of the Basque-Cantabrian Basin and Iberian Range domains, respectively, with the Sierra de Atapuerca located between both. The current structure of this zone is the result of an Alpine tectonic inversion of a previous Mesozoic extensional configuration, inherited from late Hercynian faults.

Hydrocarbon Generation History of the Eocene Source Rocks in the Fushan Depression, South China Sea: Insights from a Basin Modeling Study

Reconstruction of hydrocarbon generation history is essential to understanding the petroleum system. In this study, basin modeling was employed to investigate the primary source rocks in the Fushan Depression (FD), a significant oil-bearing basin situated in the South China Sea. The research findings indicate that different tectonic zones within the FD underwent distinct hydrocarbon generation stages. The step-fault zone and the central sag zone experienced one hydrocarbon generation stage at 10–0 Ma and 30–0 Ma, respectively. The slope zone, on the other hand, experienced two hydrocarbon generation stages, 40–23.5 Ma and 10–0 Ma, controlled by tectonic movements and heat flow variations. Furthermore, critical times for the process of the petroleum system have been determined based on this work and previous literature. The slope zone in the eastern FD is considered a favorable area for conventional hydrocarbon exploration due to the high maturity of source rocks promoted by volcanic heating and two significant oil charges. The central sag zone is identified as an excellent prospect for unconventional resources because of the substantial retention of hydrocarbons in in-source unconventional reservoirs long after hydrocarbon generation. These findings provide a valuable guide for further exploration.

Facies-related diagenesis of Jurassic sandstones, central Junggar Basin, NW China: implications for reservoir quality evolution

Abstract Hydrocarbon exploration in China has recently expanded to deep tight oil and gas from the Lower Jurassic sandstone reservoirs in the central Junggar Basin. These deeply buried sandstones (>4.5 km) have generally been overpressured due to hydrocarbon saturation, but have not been intensively investigated in terms of diagenesis and reservoir quality. The Lower Jurassic sandstones are feldspathic litharenites (average Q 28 F 29 R 43 ) and were deposited in the lacustrine–deltaic environments of the high-palaeolatitude continental basin under warm, humid climatic conditions. Progressive burial with only slight uplift of the strata led to a relatively stable burial–thermal regime, resulting in minor diagenetic changes consisting of compaction, cementation by carbonates, quartz and clay minerals, and partial dissolution of feldspars and rock fragments. Despite generally similar diagenetic histories, the studied sandstones reveal considerable variations in the development of pore systems, porosity and permeability. The best reservoirs are represented by medium- to coarse-grained depositional facies with higher porosity (average 8.43%) and permeability (average 0.59 mD). All the evidence suggests that integrated consideration of the roles of depositional settings and diagenesis, linked with burial–thermal history and overpressure evolution conditions, provides a helpful means of predicting reservoir quality.

Reconstruction of the proto-type basin and tectono-paleogeography of Tarim Block in the Mesozoic

The reconstruction of the proto-type basin and tectono-paleogeography of the Tarim Basin during the Mesozoic is crucial for hydrocarbon exploration, particularly for identifying hydrocarbon source rocks. This study reconstructs the position, thickness, and distribution of the original stratigraphy, the shortening amount by structural deformation, and the distribution of sedimentary facies in each Mesozoic period using paleomagnetic data, residual stratigraphy data, seismic profiles, and lithofacies distribution. During the Triassic period, a syn-collision thrust fault structure formed in the southern Tarim Block due to the successive collision of the Tianshuihai-Bayankara terrane, North Qiangtang terrane, and South Qiangtang terrane with the Tarim Block. The sedimentary strata mainly distributed in the Northern Depression and Kuqa Depression, and their sedimentary centers continuously moved northward. In the Early-Middle Jurassic, faulted basins representing post-collision extensional structures developed on the margins of the Tarim Block. In the Late Jurassic, the Tarim Block was compressed, and the faulted basin transformed into a depressional downwarped basin with red coarse clastic sediments due to the collision of the Amdo-Dongkacuo microcontinent with the Tarim Block. In the late Early Cretaceous, the collision between the Lhasa Block and the Tarim Block caused the entire uplift of the Tarim Block, which stopped accepting deposition except for the deposition of marine facies in the southwestern Tarim Basin influenced by a large-scale transgression event. The complex evolution of the Paleo-Tethys and Neo-Tethys Oceans during the Mesozoic significantly influenced the sediment distribution and structural features of the Tarim Basin.

Controlling factors of organic matter accumulation and lacustrine shale distribution in Lianggaoshan Formation, Sichuan Basin, SW China

The lacustrine shale, represented by the Lianggaoshan Formation, is widely distributed in oil and gas basins of China and will be a key target for unconventional hydrocarbon exploration in the future. Due to the complexity of geological conditions, the distribution of lacustrine shale and the mechanism of organic matter (OM) enrichment show significant differences between different basins. In this study, seismic interpretation, core observation, high-frequency geochemical analysis and other methods are integrated to reveal factors controlling lacustrine shale distribution and OM accumulation in lacustrine shale. The results suggest that six bottom-to-top organic-rich shale intervals are identified within the Lianggaoshan Formation due to lake-basin migration. The migration process of depocenters controls the planar distribution of lacustrine organic-rich shale. The organic-rich lacustrine shale within 1st Member and 2nd Member is characterized by relatively high paleoproductivity and dysoxic condition. The lacustrine organic-rich shale of the upper to the top of 3rd Member is characterized by relatively low paleoproductivity, relatively high terrestrial input, and dysoxic condition. Paleoproductivity and preservation condition caused by lake-level rise are generally the major influencing factor of organic matter accumulation in 1st Member and 2nd Member organic-rich shale. The input of terrestrial OM, and the condition of preservation caused by rapid deposition are the major factors controlling OM accumulation in 3rd Member of Lianggaoshan Formation.

Pore Structure and Fluid Evaluation of Deep Organic-Rich Marine Shale: A Case Study from Wufeng–Longmaxi Formation of Southern Sichuan Basin

Deeply buried (>3500 m) marine shale has become a focus point for the future exploration and exploitation of shale hydrocarbon in China. Low-temperature nitrogen adsorption (LTNA), scanning electron microscopy (SEM), nuclear magnetic resonance (NMR), and other experiments were combined to characterize the pore structure and fluid division in deep-marine shale of the southern Sichuan Basin in this study. The results suggest that the deep-marine shale had a relatively developed nanopore network, especially with honeycomb organic pores. These organic pores were largely macropores with good connectivity in three-dimensional space and constituted the major reservoir space of the deep-marine shale gas. Microfractures were predominantly clay-mineral-related fractures, and the development degree of microfractures connected with organic pores was low, which contributed to the preservation of organic pores. Within the deep-marine shale interval, the pore volumes of Section 1 and Section 3 were higher. Pore volume was predominantly contributed by pores above 10 nm, where macropores accounted for a large proportion. Based on a combination of high-speed centrifugation and gradient temperature drying, the pore fluid of deep-marine shale reservoirs was quantitatively classified into four types: clay-bound fluid, capillary-bound fluid, free-flowing fluid, and closed-pore fluid. The clay-bound fluid existed in pores of less than 4.25 nm, which cannot be exploited. Quantitative division of the shale pore system could be realized by using the pore space differences of different types of fluids.

Assessment of a Hydrocarbon Exploration Site in North Eastern State of Tripura

Recently abandoned hydrocarbon exploration sites generally support a smaller number of plants since there are few spaces for plants to grow and survive in the exploration site with all the concrete structure around and very few areas of soil to support vegetation. Metals are required by plants for their growth while a higher level can cause the plants to die. The study has been conducted to explore the concentration of metals in an abandoned hydrocarbon exploration site and their adjacent site of Tripura to determine the species diversity in the area with the metal concentration. The highest concentration of iron, chromium, and sulfur in the site were recorded in Chromolaena odorata, Urena lobata and Crotalaria pallida. All the plants collected have some levels of iron, chromium, and sulfur in their shoot as well as their roots. This study will be beneficial as the plants which have highest level of a particular metal can be used in future research to remediate the area of that metal. In this way, the cost of searching for plants to be used for phytoremediation experiment will also be reduced. The growth of plants in the abandoned hydrocarbon exploration sites will also help in reducing the contaminants of that sites.

Identification of depositional features in the Albian and Aptian sections over the hydrocarbon exploration block M2 on the Mannar Basin, Sri Lanka

The Mannar Basin extends over 45,000 km2 off the western coast of Sri Lanka. It has evolved due to the multiphase rifting between Indo-Lanka landmasses during the Barremian-Paleocene time. The sediment thickness of the basin ranges from about 4 to 10 km. The northern part of the basin is a targeted area for hydrocarbon exploration in Sri Lanka. Though two natural gas discoveries were made in 2011, the basin remains a frontier due to lack of well penetration and 3D seismic coverage. As a result, the depositional features of sediment in the basin are little known. This study focuses on identifying paleo depositional features in the Albian and Aptian strata using 650 km2 3D seismic data from the Mannar Basin. Root Mean Square (RMS) amplitude was used to characterize the depositional features in three-time windows on IHS Kingdom software (v.8.3). The results show the existence of a multi-level paleo submarine fan system in the Albian and Aptian strata. They are located relatively close to the western coastline compared to the fan system in the Eocene strata. The deposition of this paleo submarine fan system has taken place in a shelf marine environment and has been influenced by relatively high sea levels during the Albian and Aptian compared to the relatively low sea levels in the Paleocene and Eocene.

Pre-Stack Imaging for the Messinian Sub Salt Sequences in the Levantine Basin of the East Mediterranean: A Case Study, Offshore Lebanon

The Mediterranean Sea has a progressive geological significance; it is considered a vast extensive promising basin for gas exploration. Herodotus and Levantine basins are the main basins in the eastern Mediterranean basin, which are similar in their evolution stages and accommodate similar sedimentary sequences. The recent geophysical and petrophysical studies proved that Herodotus and Levantine basins are promising for gas with possible great reserves exceeding 2,000 bcm. Recent discoveries and increased exploration activities including seismic acquisition and offshore drilling made the Eastern Mediterranean a hot area for gas exploration, especially after the discovery of Zohr gas Field in 2015, offshore Egypt. However, the regional extension of the complex Messinian salt beds and domes make the exploration of high risk. The subsalt seismic imaging in a time domain and the resolution of the underlying carbonate/clastic reservoirs' primary reflections are a big challenge in this area. Therefore, the main objective of the present study is to improve sub-salt imaging with much more accurate interval velocity estimation. In the study area, offshore Lebanon, the delineated structures in the sub-salt imaging after the Pre-stack Depth Imaging were more significant compared to the Pre-Stack Time Imaging which provided optimum sub-salt imaging and enabled the accurate interpretation of the main geologic features which may increase the certainty level of the hydrocarbon exploration and discoveries.