Potential Reservoir Rocks Research Articles

Geochemical (δ13C, δ18O, 87Sr/86Sr, REEs) characterization of travertine in Tengchong, China: Insights into travertine origin and reservoir conditions

Geochemical characterization is extensively employed in travertine research, yet few studies have explored the potential of travertine geochemistry for elucidating the subterranean details of spring systems. In this study, we systematically characterized the geochemical signatures (δ13C, δ18O, 87Sr/86Sr, REEs, Zr, Th, Sr, Mn) of travertine from six spring systems in Tengchong (SW China) and compared them with those of potential reservoir rocks, aiming to understand travertine origin and assess reservoir conditions. Our results revealed substantial variations in the δ13C and δ18O of travertine among the examined systems, but the water temperature and parent CO2 assessments suggest a hot spring thermogene origin of the travertine. The 87Sr/86Sr of the studied travertine also varies significantly among the systems and overlaps with that of potential reservoir rocks. However, only the springs systems with reservoir temperatures exceeding 150 °C are likely to have precipitated travertine with 87Sr/86Sr resembling the whole-rock 87Sr/86Sr of the reservoir rocks. REE contamination by exogenous detritus and FeMn (oxyhydr)oxides was noted, emphasizing the need for careful REE contamination evaluation in travertine research. The REE comparison reveals that the studied travertine does not fully replicate the REE signature of its potential reservoir rocks, but the REE pattern, (Eu/Eu*)SN, and (Ce/Ce*)SN characteristics of the travertine reveal informative reservoir conditions. In summary, this study shows that the geochemistry of the travertine offers valuable insights into its origin and reservoir conditions. These findings could assist in the geochemical interpretation of travertine and the exaction of hypogean reservoir conditions from travertine.

Geochemistry of shales of middle Permian Barren Measures Formation, West Bokaro Basin, India: implications on provenance, paleodepositional and paleoclimatic conditions

Geochemical analyses of fine-grained clastic sedimentary rocks, such as shales, are significant since they portray the nature of the control factors from source to sink in a sedimentary basin, and help characterizing the heterogeneity in potential source and/or reservoir rocks. Bulk rock geochemistry (including major element oxides, trace elements and rare earth elements) of 20 shale samples from the Permian Barren Measures Formation, West Bokaro Basin, Peninsular India, is presented to decipher the provenance, paleo-weathering, paleotectonic, paleo-depositional and paleoredox conditions of the basin within the Lower Gondwana paleogeographic framework. X-ray diffraction (XRD) peaks and scanning electron microscopy (SEM) reveals an abundance of quartz, muscovite and clay minerals, viz., illite, kaolinite, etc., with less abundant feldspar and glauconite. The concentrations of the major element oxides, the trace elements and rare earth elements (REEs) of the shale samples are compared with predefined standards such as PAAS and UCC. The CIA (chemical index of alteration) and the A–CN–K values, based on the ratios of the major element oxides, signify intense chemical weathering. The ratios of Sr/Cu versus Rb/Sr and K2O/Al2O3 versus Ga/Rb, and high ΣREE values indicate a temperate paleoclimate. Ratios of the major element oxides (e.g., K2O/Na2O versus SiO2) suggest a passive tectonic setting. The Eu/Eu∗ and (Gd/Yb)n values depict predominantly post-Archean granitic and gneissic source rocks. The ratios of trace elements, viz., Th/Sc, Th/Co, Th/Cr, La/Sc and Eu/Eu∗, and the distribution pattern of the REEs (higher LREE in comparison to HREE) attest to a felsic-intermediate source from a nearby provenance. The redox sensitive trace elements, such as V and Ni, indicate a dysoxic condition that prevailed during deposition. The ratios of Fe2O3 versus MgO and Log (MgO/Al2O3) versus Log (K2O/Al2O3), and the ternary plots of Fe2O3–MgO–SiO2/Al2O3 suggest a non-marine to deltaic transitional environment. Such evidence of marine influences during the sedimentation of the Permian Barren Measures Formation confirms the fluvio-marine transgressive paleogeography inferred from sedimentological and paleontological inputs from the Gondwana Basins in Peninsular India, and opens up a scope for regional correlations of paleogeographic changes during the Middle Permian (Guadalupian) across the Gondwanaland.

The Derim Derim Dolerite, greater McArthur Basin, Australia: Using subsurface data to characterise a mesoproterozoic magma plumbing system

The application of high-resolution seismic reflection data has spurred major advances in knowledge of the emplacement of sub-volcanic mafic magma plumbing systems in sedimentary basins, highlighting the importance of interconnected sheet intrusions in facilitating lateral magma transport, the links between host rock mechanical properties and emplacement processes, and providing insights into how intrusive activity in basins impacts their resource potential. However, most studies have focused on Mesozoic-Cenozoic mafic magma plumbing systems situated along offshore rifted margins characterised by extensive subsurface datasets. The extensive Mesoproterozoic (c. 1300 Ma) Derim Derim Dolerite, which intrude the greater McArthur Basin in northern Australia, provide a unique opportunity to study the emplacement of a Proterozoic magma plumbing system due to its penetration by numerous hydrocarbon and mineral drillholes, in addition to seismic reflection coverage. Understanding the emplacement of this system is important because of its interactions with prospective unconventional shale reservoirs in the Velkerri and Kyalla Formations, which represent one of the world's oldest known petroleum systems. This paper focuses on characterising the intrusion emplacement and magma plumbing system using an array of subsurface data, to constrain the distribution, morphology, and emplacement mechanisms of the Derim Derim Dolerite.The morphology of the large, strata-concordant intrusions encountered at shallow present-day depths (<2 km) in the greater McArthur Basin is indicative of greater original emplacement depths of >3–4 km, suggesting a significant extent of uplift and erosion. Density-derived porosity values for the Velkerri and Kyalla Formations are anomalously low for their present-day depths, corroborating a greater palaeo-depth at time of emplacement. The extent of alteration of the host rock surrounding the Derim Derim Dolerite is highly variable, with a small number of occurrences of graphitisation of the organic matter adjacent to intrusions. However, this appears to be highly localised and the detrimental impact of the Derim Derim Dolerite on potential reservoir and/or source rocks appears generally minimal.

Distribution of magmatic intrusions and key petroleum system elements in the Pliocene–Holocene Pangani Rift Basin, Northeastern Tanzania

The sedimentary fills in the Pangani rift basin (PRB) of northeastern Tanzania have not yet been studied in detail and their petroleum potential is poorly understood. This study aims at assessing distribution of magmatic intrusions and key petroleum system elements in the PRB based on 2D seismic, remote sensing, and aeromagnetic data interpretations. Results show that evolution of the basin fill was influenced by sediment supply, magmatism, and tectonics. The PRB contains Pliocene–Holocene clastic, magmatic, and volcaniclastic deposits. The clastic sediment was sourced from the north-northeast and east-southeast of the PRB. The magmatic and volcaniclastic rocks were formed during Pleistocene–Holocene and are increasing in frequency toward the north and northeast of the basin. Tectonics and faulting created depocenters and magma conduits; magmatic intrusions and fault systems form potential petroleum traps. Seismic interpretation has shown that PRB contains potential reservoir and seal rocks for possible petroleum accumulations. Fault systems dissecting the PRB provided petroleum migration pathways from deep buried source rocks to potential reservoirs. For the first time, this study has shown that the PRB contains key petroleum system elements for petroleum accumulations to occur. Our results will be of interest to researchers working in different East African Rift basins.

Paleocene – Late Oligocene dinoflagellate cysts biostratigraphy, onshore Niger Delta

A new biostratigraphic biozonation for the Paleocene to Late Oligocene succession of the onshore Niger Delta has been developed based on the identification of significant stratigraphic dinoflagellate cyst events. This study is aimed at applying rarely used dinoflagellate cysts events in dating, correlating and inferring the paleoenvironment of penetrated sedimentary successions in the studied area. Palynological processing and analysis were carried out on two hundred and twenty ditch cutting samples recovered from two exploration wells (BN-1 and FJ-1) located in the Greater Ughelli and Northern Depobelts of the onshore Niger Delta respectively. Abundant and diverse dinoflagellate cysts recovered included marker Peridinales species Apectodinium sp., Palaeocystodinium australinum, and Gonyaulacales such as Areosphaeridium arcuatum, Cordosphaeridium gracile, Tuberculodinium vancampoae, Polysphaeridium zoharyi and Hystrichokolpoma rigaudiae. Three dinoflagellate cysts Palynological Zones - DPZ 100 (Early to Late Paleocene), DPZ 200 (Early to Late Eocene) and DPZ 300 (Late Eocene to Late Oligocene) are proposed herein. The biozones were subdivided into ten subzones based on the Top occurrence, Quantitative Tops and Quantitative base as well as ACME events of dinoflagellate cysts marker taxa which are used to date the rock sequence to be Paleocene to Late Oligocene. Abundant and diverse shallow outer neritic to inner neritic dinoflagellate cysts are identified from thick grey soft shales at the lower section of the studied wells. The upper section show significant reduction in dinocysts assemblage dominated by inner (coastal) neritic taxa. This dinocysts occurrence and distribution suggests inner (coastal) neritic paleoenvironment at the upper sections which deepened into shallow outer neritic conditions at the lower intervals of the studied wells. The thick brown to grey shales at the lower section and the medium to fine grained, moderately well sorted sandstone interbeds at the middle section of the studied wells are interpreted to be potential source and reservoir rocks respectively. These datasets are useful for correlating possible hydrocarbon source rocks and potential reservoir carrier beds in the Gulf of Guinea.

A novel approach for water reservoir mapping using controlled source audio‐frequency magnetotelluric in Xingning area, Hunan Province, China

AbstractControlled source audio‐frequency magnetotelluric is frequently used in association with other geophysical methods, especially in complex geological areas to highlight geological structures such as water reservoir rock. Although it gives satisfactory results, combining several methods requires time and expense. In addition, despite this combination, several drilling locations proposed after geophysical investigations were inaccurate, resulting in many unsuccessful drillings. The latter occurs due to the difficulty to emphasize the fracture zones properly. To work around this problem, we proposed a novel approach called pseudostratigraphic to reduce the repercussion of unsuccessful drilled boreholes and to demarcate the water reservoir rock. The technique consists to discretize the resistivity of the inverted OCCAM2D model based on the true layer resistivities collected from the borehole log data (observed layers). The discrete resistivity model is known as the new resistivity model. It is used to generate the pseudostratigraphic log at each station by pseudo‐demarcating the thicknesses of the observed layers with a low margin of error. Moreover, the combination of multiple new resistivity models from different survey lines creates a three‐dimensional pseudostratigraphic map useful to emphasize the water reservoir rock. The pseudostratigraphic implementation is carried out in the Xingning area as a real‐world case study. The results show that the intersection of the main fault (F1) and the conductive zones (≤100 Ω m) indicates the potential water reservoir rock. Its thickness is estimated around 150–600 with an error equal to ± 7°m. Based on the three‐dimensional pseudostratigraphic map, the water found in the fracture zone located under the reservoir rock is considered much hotter due to the intense geothermal activity along F1, thereby making it a better place for hot water exploitation. Finally, the pseudostratigraphic technique could be an innovative and cheap strategy to find groundwater reservoirs in complex geological areas.

MID CRETACEOUS SUBSURFACE CARBONATE DEPOSIT AND RESERVOIR DEVELOPMENT OF THE MFAMOSING LIMESTONE CALABAR FLANK

This research analyzed the reservoir quality of the Mfamosing Limestone with a view to classifying it as a potential reservoir rock within the Calabar Flank. Materials used in this research are processed seismic data acquired around the Calabar flank and well logs of three wells (A, B, C) drilled at different periods within the study area, core as well as mud log data. The procedure used involved prospect identification and mapping, structural and stratigraphic analysis, reservoir quality and classification of the carbonate rock in the study area. The results were analyzed and classified the Mfamosing Limestone using hydrocarbon storage capacity and deliverability potential. Wells A and B was drilled 0.8km apart and well C drilled 4.7km from well B which encountered the Mfamosing Limestone with logs indicating hydrocarbon in Well A which had a shallower sandstone lenses. The sandstone lens in Well A was tested for hydrocarbon and flowed briefly and stopped. Wells B and C were planned and drilled using Well A as reference amongst other parameters to evaluate the hydrocarbon potential of the Mfamosing Limestone. Wells B and C were found completely dry. Two conventional coring runs at depths 10,490ft-10,552.5ft and 10,552.5ft-10,614ft in Well B indicated that the cored intervals are light grey, moderate to very hard, and fossil rich limestone with no direct fluorescence. The core analysis results suggest that limestone is dry and highly indurated with no evidence of physical porosity. This suggest that the Mfamosing Limestone penetrated by all three wells though massive has no hydrocarbon storage capacity and deliverability potential typical of a reservoir rock. This research therefore suggests that the Mid Cretaceous subsurface Mfamosing Limestone is more of a mineral carbonate deposit than a hydrocarbon reservoir.

Petroleum System Modeling of a Fold and Thrust Belt: A Case Study from the Bannu Basin, Pakistan

This study focused on analyzing the petroleum system of the Bannu Basin, which is the foreland basin of the Himalayan fold and thrust belts in Pakistan. The objectives of this study were achieved by dividing the study area into three zones, namely, the Southwestern zone, Southeastern zone, and Northeastern zone. The regional 2D seismic lines and well log data, including the bore hole temperature (BHT) and petrophysical and geochemical data, were integrated. The seismic interpretations and geohistory plots indicate higher levels of sedimentation and abrupt sedimentation from the Miocene until the Recent era due to the initiation of Himalayan orogeny. The thermal modeling indicates that potential source rocks are present in the basin, whereas the local faults in the Southwestern and Southeastern zones act as potential traps for the preservation of hydrocarbons. It is assumed that the Tredian Formation and Lumshiwal Formation are the potential reservoir rocks in the Southwestern zone, whereas the Warcha Formation and Tredian Formation are the economic reservoirs in the Southeastern zone. However, in the Northeastern zone, no major accumulation is present. The significant sedimentation of post-Miocene formations was the major event for the generation of hydrocarbons and a critical moment for the accumulation of hydrocarbons in the study area.

North Barents Composite Tectono-Sedimentary Element

Abstract The North Barents Composite Tectono-Sedimentary Element could represent a prosperous petroleum province in the Arctic, with several large basins, platforms and highs identified. The sedimentary succession ranges from the Late Paleozoic and continues throughout most of the Mesozoic. Terrestrial sediments of the Billefjorden Group (Famennian–Visean) are likely to be present, and are overlain by evaporites and carbonates of the Gipsdalen Group (Serpukhovian–Late Artinskian). Most of the Triassic is dominated by deposits from a huge prograding deltaic system building out from the south, SE and east, becoming successively younger towards NW. The system was primarily sourced from the Urals but also partly from mainland Norway and, most probably, from Taimyr. The progradation started in the Late Permian and reached Svalbard in the Early Carnian. The entire delta system was flooded during the regional Early Norian transgression, resulting in the deposition of marine shales of the Flatsalen Formation (Svalbard) and the time-equivalent Akkar Member of the Fruholmen Formation (Barents Sea). The Cretaceous and the Paleogene are, respectively, comprehensively and completely eroded. During the Pliocene–Pleistocene, the entire Barents shelf was a site of repeated glaciations, resulting in extensive erosion. Hydrocarbon source rocks occur at several stratigraphic levels from the Carboniferous to the Jurassic, of which the most important is assumed to be the Lower–Middle Triassic Steinkobbe/Botneheia Formation. The Upper Jurassic Hekkingen Formation, where present, is likely to be immature across the whole area. Potential reservoir rocks are Permian carbonates and siliciclastic rocks of Carboniferous and Mesozoic age.

Potential petroleum prospects in the middle Benue trough, central Nigeria: Inferences from integrated applications of geological, geophysical and geochemical studies

The Middle Benue Trough (MBT) is the least well-known of the three major sub-divisions of the Benue Trough (BT) and therefore poorly understood geologically. This paper presents preliminary results of an integrated geological, aeromagnetic, gravity and geochemical studies carried out as a first step approach to petroleum exploration in the central portion (MBT) of the Benue Trough, Nigeria, so as to be able to; 1. Appraise the regional geologic setting of the MBT with a view to understanding the stratigraphy and its oil generation characteristics; 2. Determine the basin configuration and sediment thicknesses and; 3. identify and delineate “leads” or prospect areas for further detailed exploration that could lead to significant commercial discoveries of hydrocarbon in the MBT. Results have revealed the existence of petroleum systems in the MBT with the interbedded shales of the Bima and Yolde formations at the upper portions and the shales of the Asu River Group, Awe, Ezeaku and Agwu formations corresponding to the potential source rocks. The main local potential reservoir rocks are the Bima Sandstones and sandstones of the Yolde Formation coupled with the interbedded arkosic sandstones of the Awe and Keana Formations, while potential regional seals are the shales of Pindiga Formation and the arkosic sandstones overlying the shales of the Asu River Group and the basal shales of the Ezeaku formation and the upper shales horizon of the Agwu formation. Geophysical studies (Aeromagnetic/gravity survey) revealed the variability of the surface to Basement depths within the Middle Benue Trough ranging from 3 – 6 km with the deepest portions of up to 8.2 km towards the Northeastern portion of the MBT. The thick sediment piles coupled with the favorable petroleum systems, provide the conditions necessary for hydrocarbon generation, migration and accumulation. The prominent lineament structure is the NE-SW directional Keana anticline which extends along a strike for more than 100 Km from the south of Makurdi to Zurak in the northern portion. Trans tensional and trans compressional fault systems in the basin have given rise to sub-surface and extensive lineament structures systems which could either constitute major structural traps or pathways for fluid (hydrocarbon) flow. The analysis of a wide range of geochemical data from the MBT revealed TOC values ranging from 0.43 to 3.90wt% for shales/coaly shales and 14.78–79.10wt% for shaly coal/coal facies embedded in the Agwu formation with Tmax values corresponding to immature to mature stages of thermal maturation. Their petroleum potential in terms of HI values ranges from 14 to 267mgHC/gTOC in shale/coaly shale facies and 36–157mgHC/gTOC in shaly coal/coal facies, corresponding to the predominance of type III (gas-prone) in addition to type II (oil and gas-prone) organic matter suggestive of having both oil and gas generating potential. The recent discovery of significant quantity of oil (+gas) in the well Kolmani River-1 in the Gongola Sub-basin, is in strong support of its occurrence in the MBT. The paper has recommended selected prospect areas favorable for further detail hydrocarbon exploration.

Spatial distribution of micro- and nanoporosity in Oligocene Menilite and Cretaceous Lgota mudstones (Outer Carpathians): Organic porosity development as a key to understanding unconventional hydrocarbon reservoirs?

The Oligocene Menilite Beds are considered the most important source rock for hydrocarbon accumulation in the Polish Carpathian region, whereas the Cretaceous Lgota Beds have been regarded as an additional potential source rock. Understanding their petrophysical and geochemical properties is essential for evaluating the hydrocarbon potential of these beds.This paper presents mineral and organic porosity characterization and focuses on factors responsible for the development of organic pores as a reflection of the depositional and diagenetic processes. Mudstones were evaluated as potential source and reservoir rocks, describing their diagenetic and thermal history and examining their effective porosity and permeability. The results show that the Lgota Beds mudstone in the Huczwice quarry is thermally mature (late oil/early gas window, Tmax 460–470 °C), containing type III kerogen and TOC between 0.68 wt% and 4.2 wt%, in contrast to the Menilite Beds mudstone (Monasterzec outcrop), which is thermally immature (Tmax<426 °C), containing type II kerogen and TOC content from 1.24 wt% to 8.7 wt%. The geochemical properties show that the Lgota mudstone is currently an ineffective source rock, whereas the Menilite mudstone can be a potential source rock. SEM-identified pores include mineral pores, organic pores and microfractures. Organic porosity is observable both in immature oil-prone type II kerogen and highly mature gas-prone type III kerogen. The amount of pores in organic matter increases with maturity, and no relation between TOC and organic porosity development has been observed. Palynofacies analysis showed that the Menilite and Lgota mudstones are dominated by amorphous organic matter, and that the Lgota mudstone also contains opaque woody material. MICP measurements indicate high (up to 15%) effective porosity values for the Menilite Beds and up to 8% for the Lgota Beds, with very low permeability values (<0.1 mD) in both cases. Isotherms obtained from nitrogen adsorption are type IV for the Lgota Beds and type II for the Menilite Beds, while the BET surface areas are around 13 m2/g and 3 m2/g, respectively. The Lgota Beds demonstrate advanced diagenetic processes such as compaction, cementation, dissolution, replacement, and transformation, which contributed to the significant reduction in porosity, while the Menilite Beds represent an early stage of burial with the prevailing impact of compaction and thus less destruction of original pores. Finally, the Menilite Beds from the Monasterzec outcrop do not demonstrate sufficient conditions for shale-oil/-gas source rock due to the lack of proper thermal maturity. Such criterion is fulfilled by the Lgota Beds in the Huczwice quarry, but due to very low hydrocarbon potential, the Lgota mudstone is an ineffective source rock. However, given the other petrophysical and geochemical properties, the analysed formations may constitute a basis for further research on the occurrence of unconventional reservoirs in the entire Carpathian region.

Formation Evaluation of Lower Goru Sands of Khipro Block, Lower Indus Basin, Pakistan

Formation evaluation is widely used in exploration and production in order to minimize the risk, uncertainty, and understanding of the detailed characteristics of potential reservoir rocks. This study is aimed to evaluate the Petrophysical characteristics of upper and lower basal sands of the Cretaceous lower Goru Formation in Niamat-01 and Siraj-01 wells and to focus on hydrocarbon exploration potential. These wells have been drilled in the Khipro block, lower Indus basin, which is the least explored for the reservoir quality evaluation. Present study characterized the lower Goru sands of the Khipro block. It is interpreted that the thickness of upper and lower Basal sands are 13m and 10m, respectively in Naimat Basal 01, whereas 9m and 17m, respectively, are reported in SirajSouth-01. The average effective porosity is 11% in upper Basal sands while 26% is interpreted for lower Basal sand in Naimat Basal-01. An average porosity of 11% is found for upper Basal sands in Siraj South-01 and 11% for lower Basal sand. Water saturation (Sw) calculated for upper and lower Basal sands are 22% and 19%, respectively. The hydrocarbon saturation (Sh) of 78% is interpreted for upper Basal sands and 81% hydrocarbon saturation reported for lower Basal sands in Naimat basal-01. However, 36% and 45% Sw have been recognized for upper and lower Basal sands, respectively. Whereas hydrocarbon saturations of 64% and 55% are reported for the upper and lower basal sands, respectively, in SirajSouth-01. Crossover effects in front of targeted formations confirmed the presence of hydrocarbons in the zone of interest. Lower sands of the lower Goru Formation in the Khipro block are favorable for hydrocarbon production and have potential for future hydrocarbon exploration activities.

Types, Petrophysical Properties and Pore Evolution of Late Ediacaran Microbial Carbonates, Tarim Basin, NW China

AbstractThe Upper Ediacaran microbial carbonates of the Tarim Basin are potential reservoir geobodies for future hydrocarbon exploration with rising interest in exploration for deeply‐buried reserves. However, little knowledge has been acquired on the types of microbial carbonates that are present, the properties of the reservoir and the pore evolution, hampering predictions of high‐quality reservoirs in these carbonates. Integrated with petrography and in‐situ U‐Pb dating geochronology analyses, this study aims to clarify the types of microbial carbonates present and to reconstruct the pore evolution processes of the potential reservoir rocks. The Upper Ediacaran microbial carbonates of the Tarim Basin can be divided into four types, based on their features in terms of different scales (macro‐ to micro‐): microbial laminite, stromatolite, spongiomicrobialite and microbial‐peloidal wackestone/mudstone. Petrophysical properties show that all these microbial carbonates have low porosity and very low permeability with poor connectivity. These carbonates were subject to long‐term and complex diagenetic processes, mainly consisting of dissolution, compaction, pervasive dolomitization, cementation and fracturing. The most important reservoir spaces are contributed by vugs and dissolution‐enlarged pores, which are likely to have been associated with the widespread uplift of the Aksu area in the terminal Ediacaran. In contrast, the cementation of the fine‐to‐medium crystalline dolomite greatly reduced the pre‐existing pores. Pore types are closely related to different microbial fabrics, which played an important role in the pore evolution of the microbial carbonates.

PECULIARITIES OF LITHOGENESIS AND OIL AND GAS PROSPECTS OF PALEOCENE DEPOSITS OF THE NORTHERN SLOPE OF THE KARKINITsky THROUGH

The results of complex lithogenetic studies of Paleocene sediments of the northern side of the Karkinitsky Through are presented. Lateral lithological-litmological and facial variability of Paleocene deposits is characterized, which is manifested both in the whole section of the Paleocene and its individual epochs. In general, in the deposits of the Danish and Zealand epochs in the western and eastern parts of the territory, thick bodies of limestone litmites have been developed, which are overlapped by clay formations of the Tanetiant age. The central part is dominated by marl litmites. It is shown that bioherm formations located in the Golitsyno-Schmidt and Bezymenny areas are replaced by plumes of destruction and depressive deposits of the outer shelf in the direction of the Flangova structure and pelagic part of the basin. A model is substantiated (from the beginning to the end of the Paleocene) of migration of the zone of bioherm formation in the northern direction, which was caused by a general rise (with some fluctuations) in ocean level. The model expands to some extent the range of localization of promising areas of potential reservoir rocks. It is determined that the formation of natural reservoirs occurred under the influence of processes of recrystallization of the bulk of rocks and organogenic remains, dolomitization, silicification, cavern- and fissure formation. Based on the reconstruction of regional processes of generation, migration, and accumulation, it is shown that the inflow of hydrocarbon fluids that formed the Golitsyn field occurred through the area of the Schmidt structure from the eastern part of the generation center (Cretaceous deposits of the Michaivska depression). A model of the lithophysical structure of Paleocene sediments along the profile of wells: Bezimenna-2—Flangova-2—Golitsyna-2— Golitsyna-3—Schmidta-6. Four promising objects (traps of arch type, lithologically constrained type and tectonically constrained types) were identified.

Provenance of the Lower Cambrian Khewra Sandstone: Implications for Pan-African Orogeny

This study describes the sedimentological aspects of the Lower Cambrian Khewra Sandstone, along with its lithostratigraphic correlation of globally distributed coeval red sandstones to decipher the imprints of Pan-African Orogeny. Despite the economic significance of Khewra Sandstone, the understanding of its environment of deposition, provenance and lower contact with the suite of igneous body namely Khewrite is poor. The Khewra Sandstone is an allostratigraphic unit bounded by unconformities. The upward coarsening sequence with abundant sedimentary structures and varying sedimentological properties of the topmost bed suggest that the Khewra Sandstone is tempestites deposited under fluvio-deltaic depositional environment. This sandstone is dominated by subarkoses, feldspathic litharenites and sublitharenites which were derived from the craton interior to recycled orogen provenance during the Pan-African orogeny under humid to semi-humid paleoclimatic conditions. The plutonic to metamorphic characteristics of framework grains suggest that the Bundlekhand Craton, Delhi Fold Belt and Aravalli Orogen rocks were the primary provenances. The lower and middle parts of the Khewra Sandstone are significantly affected by diagenesis while the diagenetic action in upper part is negligible and it acts as a potential hydrocarbon reservoir rock. The lithostratigraphic correlation suggests a worldwide series of rifting events before the deposition of Khewra Sandstone and the presence of Khewrite at lower contact marks a similar rifting event on the Indian plate.

Facies Analysis and Paleoenvironmental Assessment of the Upper Campanian Hartha Formation in Y and J Fields Northwestern Zagros Basin, Iraq

The Upper Campanian Hartha Formation represents potential Cretaceous hydrocarbon-bearing reservoir rocks across the Y and J oilfields northwestern Zagros Basin, northern Iraq. The study objective is depositional environment which affects reservoir properties by tool, lithofacies, core, thin section, and logs, using petrel (V.2016) and strat software, facies distribution, grains, and diagenetic processes control and enhance reservoir properties which can plan platform production and minimize risks in choosing production wells location at two fields scale The current study is concerned with lithofacies and microfacies of the Hartha Formation within two fields in northern Iraq. Several subsurface well-log data, core, and cutting samples have been used in order to prepare thin sections that were subjected to sedimentological (lithofacies, and grain-size) examination. The petrography investigation revealed five rock-units including Hr. 1, 2, 3, 4, and 5, the thickness of 89 m in the Y-A field and increasing to up to 140 m in the J-B field might be due to erosion or tectonic uplift of the topography in Y subbasin. Which is locally sub-basin within study fields western banks of Tigris river as gentle slope ramp depositional condition with Spectrum microfacies from lime-mudstone to packstone texture with rudest and benthic debris enhances by diagenesis, dolomitization, dissolution moldic porosity, fracture; dolostone is more effective in the upper section of the formation in A than B Wells. Many factors, such as cementation, compaction, and pore-filling autogenic minerals, decrease reservoir quality, and their effects are similar in wells A and B.

Assessment of Paleocene to lower Oligocene formations and basement to estimate the potential hydrocarbon reservoirs using seismic inversion: a case study in the Upper Assam Shelf, India

The upper Assam shelf is a self-slope basin in north-east India, filled with nearly 7 km of sedimentary rocks of tertiary period with the granite basement and various oil fields along the border of the Naga thrust. The major producing fields are structural and strati-structural. The study area is placed in between the Mikir hills and Naga thrust. The objective of the study is to identify potential hydrocarbon reservoir zones in the geologically complex south upper of the Assam shelf using estimates of acoustic impedance and porosity derived by 3D post-stack seismic inversion. Well data, such as sonic velocity and density logs, from two wells (namely, KA and TE) are used in the inversion and validation of results. Inversion results are used to build a geological model in the form of acoustic impedance from which we derive 3D porosity cube which are used for hydrocarbon potential in the Paleocene to lower Oligocene sands, and the Precambrian basement. Although the amplitude maps provide an indication of potential reservoirs, the extent of these zones are much better identified in the inverted impedance maps and the corresponding estimated high-porosity zones. The analysis predicted the potential reservoir rocks in the Sylhet, Kopili and Barail formations, in which the Sylhet and Kopili appear to have good potential zones. Near the vicinity of the Naga thrust belt, the proximity of potential reservoir is predicted in the Kopili, Sylhet formation and in the fractured basement, respectively.

Diagenetic Control on the Distribution of Porosity within the Depositional Facies of Proterozoic Rajgarh Formation, Alwar Sub-basin, Northeastern Rajasthan

Abstract The sandstones of the Proterozoic Rajgarh Formation are texturally immature and compositionally sub-mature quartz arenite to arkose in composition. The reservoir quality of sandstones is strongly influenced by depositional facies and various types of diagenetic modifications. A significant reduction in primary porosity in the studied sandstone is mainly due to high mechanical compaction followed by chemical compaction rather than the cementation process. Arkose from the river-dominated estuary facies show infiltrated clay coating, feldspar dissolution, iron-oxide cementation, leaching of detrital by iron-oxide cement, kaolinization of feldspar, the fracturing of detrital, partial albitization and folding of mica. The pore-lining clay has helped in retaining primary porosity, and leaching and dissolution processes were the main process generating secondary porosity in this facies. Tidal flat sub-arkose petrofacies display compaction of micas and unstable rock fragments into the pseudomatrix, expansion of muscovite by kaolinite, and pore-filling silty matrix that occupied intergranular spaces. Quartz-arenite petrofacies from shallow marine deposit show grain replacive kaolinite, pyrite precipitation, glauconite authigenesis, muscovite bending, albitization of plagioclase, feldspar overgrowths, dissolution, and grain fracturing. Pyrite plays a significant role in the reduction of both primary and secondary porosity by precipitating in intergranular spaces and in dissolution voids of feldspar. Moreover, fractures in detrital act as a second cycle porosity generation process in the shallow marine petrofacies. The linking between the diagenetic processes and depositional facies provides a geologic model for hydrocarbon exploration through reservoir quality prediction. Therefore, the petrographic observations indicate quartz-arenite (shallow marine facies) and sub-arkosic sandstones (tidal flat facies) are the least suitable latent reservoir because of their lowest primary and secondary porosity and unconnected pore spaces. Arkosic (river-dominated estuary facies) compositions are considered to be appropriate frameworks for potential reservoir rocks. This study reveals that the depositional environment largely controls the diagenetic pathways and hence, influences the reservoir quality.

Seismic Lithofacies Distribution Modeling Using the Single Normal Equation Simulation (SNESIM) Algorithm of Multiple-Point Geostatistics in Upper Assam Basin, India

Recently, multiple-point geostatistical simulation gained much attention for its role in spatial reservoir characterization/modeling in geosciences. Accurate lithofacies modeling is a critical step in the characterization of complex geological reservoirs. In this study, multiple-point facies geostatistics based on the SNESIM algorithm integrated with the seismic modeling technique is used as an efficient reservoir modeling approach for lithofacies modeling of the fluvial Tipam formation in the Upper Assam Basin, India. The Tipam formation acts as a potential reservoir rock in the Upper Assam Basin, India. Due to the basin geological complexity and limitation in seismic resolution, many discontinuities in depositional channels in this fluvial depositional environment have been identified using conventional lithofacies mapping. This study combines three techniques to reproduce continuity of the lithofacies for better reservoir modeling. The first is simultaneous prestack inversion for inverting prestack gathers with angle-dependent wavelets into seismic attributes. A cross-plot of P-impedance and VP/VS ratio from well-log data was used to classify the different reservoir lithofacies such as hydrocarbon sand, brine sand, and shale. The second is the Bayesian approach that incorporates probability density functions (PDFs) of non -parametric statistical classification with seismic attributes for converting the seismic attributes into lithofacies volume and the probability volumes of each type lithofacies. The third technique is multiple-point geostatistical simulation (MPS) using the Single Normal equation Simulation (SNESIM) algorithm applied to training images and probability volumes as constraints for a better lithofacies model. These integrated study results proved that MPS could improve reservoir lithofacies characterization.

Hudson Strait Platform and Basins Tectono-Sedimentary Element, Northeast Canada

Abstract The Hudson Strait Platform and basins Tectono-Sedimentary Element (HSPB TSE) is part of a major topographical feature that connects Hudson Bay and Foxe Basin with the Labrador Sea in the Canadian Arctic. The Paleozoic succession (Ordovician–Silurian) unconformably overlies the Precambrian basement and reaches a maximum preserved thickness of less than 600 m on the islands. High-resolution marine seismic data indicate that the offshore part of the Hudson Strait is underlain by several fault-controlled sub-basins with a half-graben geometry. The sedimentary succession in the sub-basins is thicker than the one preserved in nearby islands, and includes an upper sedimentary package for which the nature and age remain poorly constrained. Upper Ordovician source rocks have been mapped onshore. Known potential reservoir rocks consist of Ordovician clastics and Ordovician–Silurian reefs and dolostones.