Regional Seal Research Articles

Occurrence, residency, and habitat characterization of leopard seals in Chile

Leopard seals have traditionally been considered Antarctic predators with a Southern Ocean distribution. Historically, sightings north of the Antarctic Polar Front were considered extralimital. However, recent studies suggest a significant presence of leopard seals in subantarctic regions. Here, we assess the spatial occurrence, residency status, and temporal trends of leopard seals in Chile using historical records, stranding reports, standardized monitoring data, photo-identification (photo ID) catalogs, and sightings from four research expeditions. We also characterize glaciers where sightings are concentrated, identifying glaciological and geomorphic attributes that prolong iceberg residency time, which is linked to high leopard seal concentrations. Based on these attributes, we evaluated other potential suitable glacial habitats in Patagonia. We obtained 438 sighting records of leopard seals from 1927 to 2023. Over the last 15 years, we documented a 4-18% annual increase in stranding events reported to national authorities. Most sightings (75%) were concentrated in two hotspots: National Park San Rafael Lagoon, located in Northern Patagonia, and Parry Fjord in Tierra del Fuego. Using photo ID catalogs, we identified 19 resident leopard seals, including 16 multi-year residents observed between 2010-2023 (10 in San Rafael, 6 in Tierra del Fuego) and 3 potential residents (observed multiple months in the same year in Tierra del Fuego). San Rafael monitoring data showed no inter-annual trend, but seasonal trends were observed. We also provide evidence of breeding in Chile, with records of at least 14 pups born and at least two females giving birth in multiple years. Our habitat characterization suggests that calving flux, fjord sinuosity, and fjord width variation are crucial for prolonging iceberg residency in hotspot areas. Based on these attributes, we identified 13 additional fjords in Patagonia as “very likely” suitable for leopard seals. Our study confirms that Patagonia is part of the species’ breeding distribution, shifting the paradigm that leopard seals are merely visitors north of the Antarctic Polar Front. Given the limited number of suitable glaciers in Chile and the potential impacts of climate change, our assessment highlights glacial retreat as a major threat for the ecosystem of this pagophilic marine apex predator in South America.

An experimental investigation on the CO2 storage capacity of the composite confining system

Assuring secure containment of stored CO2 is of paramount importance—for climate change mitigation, for permitting, and for reassuring the public. Regional seals, such as those sealing petroleum accumulations, have proven to be effective for securing CO2. However, the goal of permanent sequestration can also be satisfied with “composite confining systems” consisting of multiple, possibly discontinuous flow barriers that, in aggregate, create a system with very high permeability anisotropy and effectively retard the vertical migration of CO2. This study focuses on investigating the barrier characteristics necessary for effective containment of CO2, using both physical flow experiments and modified invasion percolation simulations. The simulations are calibrated to the physical experiments and are used to further extend the analysis. Results show that for a composite confining system, a) even barriers with low capillary entry pressure contrast to the underlying flow unit can divert rising CO2; b) curved or anticlinal barrier topography can enhance CO2 trapping; c) fining-upward gradations make little difference to barrier effectiveness or CO2 retention; d) longer barriers retain more CO2 regardless of barrier topography. Finally, field-scale simulations have demonstrated the importance of barrier length for increasing CO2 storage capacity. The results presented can be used to inform the development of new screening criteria for characterization and effectiveness of composite confining systems.

Novel insights about petroleum systems from source and reservoir rock characterization, Cretaceous Deposits, Babouri-Figuil Basin, Northern Cameroon

The Babouri-Figuil Basin (BFB) is a frontier basin for petroleum in Cameroon. It belongs to the series of Cretaceous rift basins of the West and Central Rift System (WCARS), the origin of which is related to the opening of the South Atlantic. Within the same rift system, commercial hydrocarbon accumulations have been discovered in Chad, Sudan, Niger and, more recently, in Nigeria (Gongola Basin). The study of the geology of the BFB just recently received considerable attention, mainly because of its presumed hydrocarbon potential. In the pursuit of researching possible petroleum systems in the BFB, the current study provides a first look into the characterization of source and reservoir rock and its integration into a 2D lithostratigraphic model. The study was solely based on outcrop samples. Black shale and massive claystone are good to excellent hydrocarbon source rocks [e.g., up to 38 wt% total organic carbon (TOC), up to 943 mg/g hydrogen index, up to 85 m thickness, up to 20–30 km lateral extension], with moderate to high values of extractable organic matter (e.g., >10,000 ppm). Calcareous claystone, on the other hand, are poor source rocks [e.g., <0.20 wt% TOC]. The samples are thermally immature, except for those located close to volcanic intrusion at Golombe that have reached the threshold for oil generation (Tmax >435 °C, production index >0.1). The petrographic analysis of sandstone revealed that they are fine-grained to coarse-grained, poorly to moderately sorted, texturally and compositionally immature to submature, subarkosic to arkosic arenites. The main diagenetic processes that affected sandstones are as follows: moderate to intense compaction characterized by the development of long, concavo-convex, and sutured contacts between grains; cementation through calcite, iron oxide, and quartz cements; alteration of mica and feldspar grains; partial to complete dissolution of feldspar, mica, amphibole grains, and calcite cement; and the replacement of feldspar and mica grains by clay minerals. Alteration and dissolution increase the porosity of sandstone through the creation of secondary pores. However, mechanical compaction through the development of a pseudomatrix and cementation as pore-filling materials have significantly reduced the quality of sandstone beds as conventional petroleum reservoirs. Hence, the best reservoir-quality sandstones in the basin are generally located in the upper portion of the basin in terms of its lithostratigraphic model. They are the cleanest sandstones with the smallest amount of cement and the lowest ductile grain content (pseudomatrix), with a thickness that varies from 3 m to 120 m and a lateral extension of 20 km. The lithostratigraphic model of the basin is characterized by an extensive lacustrine environment that provided a thick sequence of organic-rich formations; sand deposited as extensive reservoirs sandwiched between shale/claystone beds; the development of stratigraphic traps through lateral facies change; and the widespread deposition of lacustrine and floodplain claystone that provide regional seals. The similarities between the Babouri-Figuil Basin and proven petroleum systems in other WCARS rift basins suggest that the basin may host at least one petroleum system where actively generating source rocks are present.

Nigerian Case Study Explores Drilling Through Shales Below Depleted Sands

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 217195, “Drilling Through Shales Below Depleted Sands: Case Study of a Niger Delta HP/HT Gas Development Well,” by Stella Ogbodu, SPE, Bart Tichelaar, and Chibueze Amadi, SPE, Shell, et al. The paper has not been peer reviewed. _ Choosing the right casing depth is a key step in executing high-pressure/high-temperature (HP/HT) wells in the geologically complex Niger Delta. In the wells of Astra East Field, a casing shoe was set in a homogeneous shale of approximately 200 ft vertical thickness located between overlying heavily depleted sand and underlying overpressured sand. The question remained, however, as to what depth the casing shoe should be set to minimize the risk of kicks or wellbore instability and losses. To address this issue, wireline log data and drilling observations from other wells in the same field were analyzed and evaluated. Introduction The Astra East field was planned to provide feedstock gas. The field is in the Central Swamp depobelt of the Niger Delta and is 90 km west of Port Harcourt. More than 40 wells have been drilled in the field to date. A regional shale layer at approximately 11,400 ft subsea caps the regional top of overpressure in this field. This approximately 200-ft-thick shale layer vertically segments the field into two pressure regimes: a near-hydrostatic regime above it and an overpressured regime below. In other words, this shale layer acts as a regional pressure seal. Historically, oil and gas production has focused on the reservoirs above this regional seal, resulting in pressure depletion to pore-pressure values below hydrostatic in some of the reservoirs. Of the wells drilled in the field, only a handful penetrate the deeper overpressured section below the regional pressure seal and have faced various drilling challenges. Location and Geology of the Study Area The Astra East study interval is part of the Agbada formation, a paralic sequence of sands and shales up to 4 km thick in the central parts of the basin. Three lithostratigraphic subdivisions exist in the delta: the prodelta Akata shale formation, the paralic deltaic Agbada formation, and the continental Benin formation. These units represent an overall regressive, progradational stratigraphy. Depletion History and Drilling Performance The produced reservoir that sits immediately above the regional pressure seal is the C reservoir. Because hydrocarbon production from the C reservoir began more than 50 years ago, reservoir pressure gradient has depleted from approximately 5,150 psi before production to subhydrostatic. During the last 20 years, this depletion has remained relatively constant at approximately 1,660 psi below hydrostatic. The underlying, unproduced D reservoir is not depleted and is, in fact, at its virgin pressure, which is overpressured at approximately 3,035 psi above the hydrostatic pressure. This implies that the approximately 200-ft-thick intrareservoir shale between C and D reservoirs holds a large differential pore pressure of approximately 4,700 psi for the last 20 years. In fact, because the aquifer of the C reservoir was hydrostatic at virgin conditions, a large pressure differential was in place across this intrareservoir shale (between C and D reservoirs) even before production started.

Hydrocarbon accumulation characteristics in basement reservoirs and exploration targets of deep basement reservoirs in onshore China

Based on the global basement reservoir database and the dissection of basement reservoirs in China, the characteristics of hydrocarbon accumulation in basement reservoirs are analyzed, and the favorable conditions for hydrocarbon accumulation in deep basement reservoirs are investigated to highlight the exploration targets. The discovered basement reservoirs worldwide are mainly buried in the Archean and Precambrian granitic and metamorphic formations with depths less than 4 500 m, and the relatively large reservoirs have been found in rift, back-arc and foreland basins in tectonic active zones of the Meso-Cenozoic plates. The hydrocarbon accumulation in basement reservoirs exhibits the characteristics in three aspects. First, the porous-fractured reservoirs with low porosity and ultra-low permeability are dominant, where extensive hydrocarbon accumulation occurred during the weathering denudation and later tectonic reworking of the basin basement. High resistance to compaction allows the physical properties of these highly heterogeneous reservoirs to be independent of the buried depth. Second, the hydrocarbons were sourced from the formations outside the basement. The source-reservoir assemblages are divided into contacted source rock-basement and separated source rock-basement patterns. Third, the abnormal high pressure in the source rock and the normal–low pressure in the basement reservoirs cause a large pressure difference between the source rock and the reservoirs, which is conducive to the pumping effect of hydrocarbons in the deep basement. The deep basement prospects are mainly evaluated by the factors such as tectonic activity of basement, source-reservoir combination, development of large deep faults (especially strike-slip faults), and regional seals. The Precambrian crystalline basements at the margin of the intracontinental rifts in cratonic basins, as well as the Paleozoic folded basements and the Meso-Cenozoic fault-block basements adjacent to the hydrocarbon generation depressions, have favorable conditions for hydrocarbon accumulation, and thus they are considered as the main targets for future exploration of deep basement reservoirs.

Qualifying Bismuth Plug Technology in Mozambique

_ Over the past 10 years, bismuth plugs have been used more often to solve complex downhole integrity issues and to permanently abandon wells, both on and offshore. As bismuth technology is relatively new to the market, it often needs to be qualified in-country before use on a larger scale. This is a significant barrier to the adoption of new technologies in general within the industry and not unique to the use of bismuth as a permanent sealing barrier. Bismuth and bismuth-based alloys have unique properties that allow them to be used as a sealing material that has the potential to change the industry. It has a specific gravity of 10 which means it is 10 times denser than water. In molten form it can displace any fluid in the wellbore. Not only is it dense but in its molten form it also has a viscosity like water, which means it can flow easily and through perforations, cracks, crevices, or any micro annuli without the need of any pumping equipment. The most interesting property however is its ability to expand on solidification. BiSN uses proprietary thermite heaters to melt bismuth-based alloys downhole, which then flow into the annulus through perforations or section milled windows taking the shape of volume they are filling up. The alloy on solidification then expands (like ice) which creates the gas-tight seal against the surface it is expanding. These alloys not only create a solid mechanical barrier but are also highly corrosion resistant to H2S, CO2, acids, and other wellbore fluid that might be present, thereby creating a barrier that can last forever or be classified as “eternal.” Compared to existing traditional sealing technologies, a bismuth plug requires a significantly shorter seal, resulting in less materials, section milling, and time needed for deployment. For example, a traditional cement plug might need to be hundreds of feet in length where a bismuth plug can be set at as little as 6 ft. Field Test—Context, Challenges, and Methodology In May 2023, BiSN was contracted to fulfill a rigless plug and abandonment (P&amp;A) campaign for Sasol in Mozambique. Before proceeding, BiSN and Sasol worked together on a well in Mozambique to qualify BiSN bismuth technology as a permanent abandonment solution in the country. The well chosen for the seal test had several complicating factors including the need to set the seal in open hole through perforations and the thin caprocks located in the region. The overall goal of the field test was to isolate gas-bearing silt from shallower formations by forming an effective seal. To accomplish this, the bismuth plug was required to be set with a 10-m shale window identified by Sasol as a suitable location to set a regional seal to essentially restore the caprock. Previous explorations had revealed areas of patchy cement from earlier P&amp;A attempts.

GEOLOGICAL AGE EVALUATION OF SAPELE DEEP FIELD, DELTA STATE, SOUTH-SOUTH NIGERIA

One of the most productive fields in the Niger Delta is the Sapele Deep field, an onshore field of OML 41 that is situated in the Northwestern region (Greater Ughelli depobelt) of the oil province. The Niger Delta chronostratigraphic map from SPDC (2010) and well-log, seismic, and biostratigraphic data from six wells within the Niger Delta Province were used to conduct the age assessment of the field. Petrel®2016 (Schlumberger software) was used in the interpretation of seismic and well log data used in this research. Age of rocks within the depositional basins of the study area ranges from early Miocene to late Miocene and this was established through the delineated maximum flooding surface and marker fauna from the regional seal of marine transgression which are Me-2-Bolivina-48, Me-1-Haplophragmoides-24, Tor-2-Uvigerina-8, Tor-1-Nonion-4, Ser-3-Dodo Shale, Ser-2-Cassidulina-7, Ser-1-Bolivina-25, Lang-1-Bur-5-Chiloguembelina-3, and Bur-3-Ogara Shale. The specified reference fossils from depths of 6814.5 ft to 12573 ft include Globorotalia plesiotumida, Globigerinoides extremus, Neogloboquadrina acostaensis, Globorotalia lenguaensis, Globoturborotalita nepenthes, Orbulina suturalis, Fohsella robusta, Fohsella fohsi, Fohsella peripheroacuta, Fohsella praefohsi, Praeorbulina glomerosa, Fohsella birnageae, Globigerinatella insueta, Praeorbulina sicana, and Catapstdrax dissimilis. The depth range for these markers spans from 6814.5 ft to 12573 ft.

Relationship between structural style and the petroleum system in the siba gas field, southern Iraq

The Siba gas field is the only non-associated gas field in southern Iraq, located in an area primarily for oil production. The study aimed to identify the reasons for gas generation and accumulation in the field's Lower Cretaceous Yamama reservoir and the source of the gas. The study focuses on seven wells from the field, namely Siba-1, 4, 5, 6, 7, 8, and 9, and the structural and tectonic settings of the field were studied by interpreting seismic data. Geometric analysis showed that the Siba field is a non-cylindrical, asymmetrical, open, anticlinal fold. The anticline is northeast-southwest-trending with two culminations, of which the northeastern one is the higher by about 100 m. The Siba field overlies deepest parts of the Mesopotamian foreland basin, almost adjacent to the Zagros orogenic front, where burial depth and thermal conditions were ideal for organic-matter maturation and increased pore pressures that lead to hydrocarbon migration from Middle Jurassic source rocks to the Lower Cretaceous Yamama Formation reservoir. The geochemical parameters of oils from the Yamama Formation are like those of oils from Sargelu Formation in adjacent fields, indicating that the Middle Jurassic Sargelu Formation is the most likely source of Siba hydrocarbons. Vitrinite reflectance and thermal analyses of oils from the Yamama reservoir (0.87% R0; 128.1 °C) and from the Sargelu Formation (1.36% R0; 156.96 °C) show that only the Sargelu Formation had the right burial depths and temperatures in this area during Miocene deformation to source Yamama hydrocarbons in the Siba field. Although the anhydrites of the Upper Jurassic Gotnia Formation form a prominent regional seal separating Jurassic source rocks from Cretaceous reservoirs, structure-contour maps and seismic analyses indicate that many faults and fractures, mostly related to Miocene deformation, penetrate Gotnia anhydrites. Hence, the study interprets that these faults, as well as facies changes on the margin of the Gotnia basin, seriously impaired the Gotnia seal, allowing the vertical migration of hydrocarbons from the Middle Jurassic Sargelu Formation into the Lower Cretaceous Yamama reservoir in the Siba field.

Depositional environments as a framework for genetic classification of the basic criteria of petroleum potential

Most classifications of reservoirs, seals and source rocks based on the ability of the rock to generate, accumulate and preserve hydrocarbons, and the genesis of rocks is not always taken into account. The article presents a ranking scheme for continental, coastal-marine and marine sedimentation environments that determine the genesis and properties of the basic criteria of petroleum potential – source rocks, reservoirs, seals and pinch-out traps. Rocks, which can consider as source rock, reservoirs and seals are formed in each depositional environment. However, their structure, mineral composition and distribution area will differ from each other depending on the sedimentary environment and conditions. A combination of elements of the hydrocarbon system formed, corresponding to the sedimentation environment and are characteristic for basins of various types. Continental environments are favorable for the formation of reservoirs and local seals, while the accumulation of source rocks limited by lacustrine, floodplain, and swamp facies. The coastal-marine environment is favorable for the formation of all the basic criteria of petroleum potential, and the transgressive-regressive cyclicity determines the interbedding of source rocks, reservoirs and seals in the section. The marine depositional environments are most favorable for the formation of regional seals and source rocks, including high-carbon formations. The proposed ranking scheme of sedimentary environments and the basic criteria of petroleum potential genetically related to them is applicable in system analysis and selection for analogues of petroleum system elements in sedimentary complexes formed in similar depositional environments.

Petroleum geology and sub-source hydrocarbon accumulation of Permian reservoirs in Jinan Sag, eastern Junggar Basin, NW China

According to the latest drilling and the analysis of the burial history, source rock evolution history and hydrocarbon accumulation history, the sub-source hydrocarbon accumulation characteristics of the Permian reservoirs in the Jinan Sag, eastern Junggar Basin, are clarified, and the hydrocarbon accumulation model of these reservoirs is established. The results are obtained in four aspects. First, the main body of the thick salified lake basin source rocks in the Lucaogou Formation has reached the mature stage with abundant resource base. Large-scale reservoirs are developed in the Jingjingzigou, Wutonggou and Lucaogou formations. Vertically, there are multiple sets of good regional seals, the source-reservoir-caprock assemblage is good, and there are three reservoir-forming assemblages: sub-source, intra-source and above-source. Second, dissolution, hydrocarbon charging and pore-preserving effect, and presence of chlorite film effectively increase the sub-source pore space. Oil charging is earlier than the time when the reservoir becomes densified, which improves the efficiency of hydrocarbon accumulation. Third, buoyancy and source-reservoir pressure difference together constitute the driving force of oil charging, and the micro-faults within the formation give the advantage of “source-reservoir lateral docking” under the source rock. Microfractures can be critical channels for efficient seepage and continuous charging of oil in different periods. Fourth, the Jingjingzigou Formation experienced three periods of oil accumulation in the Middle–Late Permian, Middle–Late Jurassic and Late Neogene, with the characteristics of long-distance migration and accumulation in early stage, mixed charging and accumulation in middle stage and short-distance migration and high-position accumulation in late stage. The discovery and theoretical understanding of the Permian reservoirs in the Jinan Sag reveal that the thrust belt has good conditions for forming large reservoirs, and it is promising for exploration. The study results are of guidance and reference significance for oil and gas exploration in the Jinan Sag and other geologically similar areas.

Перспективы нефтегазоносности нижнедевонских отложений гряды Чернышева (Тимано-Печорская нефтегазоносная провинция)

The Chernyshev Swell is one of the poorly studied and promising areas for the hydrocarbon (HC) exploration in the north of the Timan-Pechora Petroleum Province. Lower Devonian carbonate deposits as part of the Middle Ordovician-Lower Devonian petroleum complex are considered as a priority object for the HC exploration. The study of the Lower Devonian deposits in well core and outcrop showed that the reservoirs were represented mainly by fractured-cavern-pore and cavern-fractured dolomites. The porosity of the rocks reaches 9.3 % with a predominance values in the range of 0.5–1.5%. The permeability values up to 1.0×10–15 m2 are predominant, less often in the range of 1–10×10–15 m2. Such filtration and capacitive properties characterize them as low-capacity and low-permeable reservoirs. The best properties of reservoirs are associated with facies of carbonate shallows, small biostomes and biogerms. The petroleum source rocks are contained in the clay-carbonate unit of the Ovinparma Formation. The OM richest rocks (Corg — 1.08–1.88%) are characterized by the values of (S1+S2) generation potential — 2.18–8.65 mg HC/g rock and hydrogen index HI — 153–432 mg HC/g Corg, which classifies them as medium petroleum source rocks. Thus, the presence of reservoirs, petroleum source rocks and overlapping by the Upper Devonian regional seal is a favorable condition for the formation of HC deposits in the Lower Devonian.

Arctic regions of Western Siberia. A comparative analysis of the geological structure and gas and oil presence. Prospects for new discoveries

Introduction. An analysis of the geological structure and gas and oil presence of the Arctic region in Western Siberia is carried out.Aim. To assess the potential and undiscovered gas resources, as well as to forecast prospects and potential of explored reserves for 2023–2040.Materials and methods. The geological structure and gas and oil presence specific to Arctic regions and regions of Western Siberian megabasin and megaprovince, including Yamal, Gydan, Southern-Kara with bays (shelf) and western part of the Yenisei-Khatanga, were analysed. In these locations, hydrocarbon reserves (HC) of non-associated gas, crude and condensate, HC accumulations in the volume of a sedimentary Jurassic-Cretaceous cover (Cenozoic upper regional seal), oil-and-gas and geostatistics, as well as the scale of layers and deposits, were assessed.Results. The resources of Yamal-Kara and Gydan-Yenisei land and shelf regions were assessed. A forecast was made concerning the potential and undiscovered gas resources, as well as possible increments of explored reserves for 2023–2040. The comparative resource geostatistics of the land and shelf appears to be somewhat premature. However, according to most researchers, land undiscovered giants (&gt;0.3 trillion m3) can be already excluded, while shelf supergiant gas fields are possible (unique ones are excluded). Nevertheless, their number can only be evaluated by prospecting and exploration in the most favourable structural and tectonic conditions.Conclusion. The Yamal-Kara region can become the largest strategic gas production centre of both Western Siberia and Russia as a whole, while Gydan-Yenisei region can be a tactical centre.

Characterization of ultra-deeply buried middle Triassic Leikoupo marine carbonate petroleum system (!) in the Western Sichuan depression, China

Ultra-deeply buried (>5000 m) marine carbonate reservoirs have gradually become important exploration targets. This research focuses on providing an understanding of the basic elements of the ultra-deeply buried Middle Triassic Leikoupo marine carbonate petroleum system within the Western Sichuan Depression, China. Comprehensive analyses of organic geochemistry, natural gas, and C–H–He–Ne–Ar isotope compositions suggest that the reservoir is charged with compound gases from four source rock units including the Permian Longtan, Middle Triassic Leikoupo, Late Triassic Maantang and Xiaotangzi formations. Approximately a 50-m thick outcrop and 100-m length of drilling cores were examined in detail, and 108 samples were collected from six different exploration wells in order to conduct petrographic and petrophysical analyses. Thin-section and scanning electron microscope (SEM) observations, helium porosity and permeability measurements, mercury injection capillary pressure (MICP) analysis, and wire-line logging (5500–6900 m) indicate that the reservoir lithologies include argillaceous algal limestones, dolograinstones, crystalline dolostones, and microbially-derived stromatolitic and thrombolitic dolostones. Reservoir properties exhibit extreme heterogeneity due to different paleogeographic environmental controls and mutual interactions between constructive (e.g., epigenetic paleo-karstification, burial dissolution, structural movement, pressure-solution and dolomitization) and destructive (e.g., physical/chemical compaction, cementation, infilling, recrystallization, and replacement) diagenetic processes. An unconformity-related epigenetic karstification zone was identified in the uppermost fourth member of the Leikoupo Formation, which has developed secondary solution-enhanced pores, vugs, and holes that resulted in higher porosity (1.8–14.2%) and permeability (0.2–7.7 mD). The homogeneity and tightness of the reservoir increases with depth below the unconformity, and it is characterized by primary intergranular and intracrystalline pores, solution pores, fractures, stylolites, and micropores with a lower helium porosity (0.6–4.1%) and permeability (0.003–125.2 mD). Regional seals consist of the Late Triassic Xujiahe Formation, comprised of ∼300 m of mudstones that are overlain by ∼5000-m thick of Jurassic to Quaternary continental argillaceous overburden rocks. Effective traps are dominated by a combination of structural-stratigraphic types. Paleo-reservoir crude oil cracking, wet-gases, and dry-gases from three successive hydrocarbon generation processes supplied the sufficient hydrocarbon resources. The homogenization temperatures of the hydrocarbon-associated aqueous fluid inclusions range from 98 to 130 °C and 130–171 °C, which suggests hydrocarbon charging occurred between 220–170 Ma and 130–90 Ma, respectively. One-dimensional basin evolution models combined with structural geologic and seismic profiles across wells PZ1-XQS1-CK1-XCS1-TS1 show that hydrocarbon migration and entrapment mainly occurred via the unconformity and interconnected fault-fracture networks with migration and charging driven by formation overpressure, abnormal fluid flow pressure, and buoyancy forces during the Indosinian and Yanshanian orogenies, with experiencing additional transformation occurring during the Himalayan orogeny. The predicted estimated reserves reached ∼300 × 109 m3. The results provide excellent scientific implications for similar sedimentary basin studies, it is believed that abundant analogous deeply buried marine carbonate hydrocarbon resources yet to be discovered in China and elsewhere worldwide in the near future.

Hydrocarbon accumulation conditions and favorable exploration zones in the Lunpola Basin, Tibet

By systematically reviewing and summarizing the previous studies on the petroleum geology of the Lunpola Basin, combined with the latest oil and gas exploration results, the oil and gas accumulation conditions of this basin are summarized, and the favorable zones with the most exploration potential are pointed out. The results show that: ① The Paleogene mainly develops three sets of source rocks, including Niu-1 section, Niu-2 section and lower Niu-3 subsection. The lithology is mainly semi-deep and deep lacustrine gray-dark shale. Among them, the source rock of Niu-2 section is the best. However, the source rock of Niu-1 section is only developed in the Jiangjiacuo depression. The effective source rocks have the largest thickness in the central and western parts of the basin and have the best hydrocarbon-generating capacity. The thickness and abundance of the source rocks have decreased eastward. The organic matter are mainly Type I and Type II1, with a maturity of 0.58%–1.08%. ② The study area is dominated by clastic rock reservoirs, which can be divided into three types according to the strata distribution, and the overall reservoir conditions are not good. The reservoir porosity is between 0.1% and 32.6%, mainly between 2.0% and 10.0%, with an average of 6.5%; the permeability is between 0.0005 mD and 116.0 mD, mainly between 0.01 mD and 0.5 mD, which means ultra-low porosity and ultra-low permeable fracture-porous reservoirs. ③ Three sets of seals are mainly developed in the Lunpola Basin, including two regional seals of the middle Niu-2 subsection and Dingqinghu section, and a direct seal of upper Niu-2 subsection. These three sets of seals are well developed and have good preservation conditions in the relatively stable central depression and the footwall of thrust nappe structural belt . ④ The oil and gas reservoirs in the Lunpola Basin have the distribution law of “structural traps in the north and south, and lithologic traps in the center”. Structural traps are mainly distributed in the thrust nappe belt in the north and the Changshan uplift in the south, forming “self-generation and self-storage” or “lower-generation and upper-storage” reservoirs. While lithologic traps are mainly distributed in the central sag, forming “self-generation and self-storage” reservoirs. ⑤ The source-reservoir-caprock combination conditions are good in the structural traps in the footwall of the northern thrust nappe belt and the lithologic traps in the southern slope belt of Jianjiacuo depression,, and they are the most favorable oil and gas exploration zones in the Lunpola Basin.

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.

Stratigraphic palynology and micropaleontological study of the Cretaceous-Paleogene succession of the Nani-1 well of the Anambra and Niger Delta basins: Implications for hydrocarbon exploration

Integrated palynological and micropaleontological analyses were carried out on the Nani-1 well drilled into the Anambra and Niger Delta basins of Nigeria. The study is aimed at reconstructing biozones and paleoenvironments of deposition, as well as deducing the sequence stratigraphic framework of the Cretaceous-Paleogene successions of an area containing key elements for hydrocarbon exploration. Encountered lithofacies succession of sandstone, siltstone, dark-grey to black shale, and coal beds comprises six lithostratigraphic units, namely the Nkporo Group (Campanian-Maastrichtian), Mamu Formation (Middle Maastrichtian), Ajali Formation (Middle-Late Maastrichtian), Nsukka Formation (Late Maastrichtian), Imo Formation (Danian-Thanetian) and Ameki Group (Eocene). Fourteen dinoflagellate zones (A-N) and seven pollen and spore subzones (A1-G1) are recognized based on the first occurrence of two or more species. Two major stratigraphic events are documented: (1) dinoflagellate cyst (dinocyst) zone G at 880 m depth marked by first appearance of Danea aff. californica and Danea cf. mutabilis in association with Cordosphaeridium fibrospinosum, and the last occurrence of Danea aff. californica and Phelodinium magnificum place the Cretaceous-Paleogene (K/Pg) boundary in the lowermost part of the Imo Formation; and (2) a hiatus characterized by a starved section observed at 380 m directly overlain by the Early Eocene assemblages of the Ameki Group indicates a sequence boundary at Imo/Ameki Boundary. Thus, a chronostratigraphic chart is developed for parts of the Anambra Basin and the Niger Delta. Six depositional environments which include marginal to shallow marine, marshy lagoon to estuarine, shallow neritic and tidally influenced fluvial channel are identified, and palynostratigraphic evidences indicate that fresh water palynomorphs are present in the Lower Maastrichtian strata. Four sequence boundaries and four maximum flooding surfaces are also identified within the Maastrichtian–Early Eocene sediments. The paleoenvironmental reconstruction shows that possible hydrocarbon reservoirs in the basin are the marine sandstone facies of the Nkporo Group and Mamu Formation. Their shale members constitute potential source rocks, while the overlying shale units of the Nsukka and Imo formations may provide regional seals for hydrocarbon habitation.

Seismic sequence stratigraphy and depositional evolution of the Cretaceous-Paleogene sedimentary successions in the offshore Taranaki Basin, New Zealand: implications for hydrocarbon exploration

The seismic stratigraphy and sedimentary facies of the Cretaceous and Paleogene sedimentary successions in north-eastern offshore part of Taranaki Basin, New Zealand have been investigated in order to unravel their depositional evolution and identify the potential hydrocarbon plays. Interpretation of regional seismic lines covering the entire shelf-slope and deepwater regions as well as integrating seismic and sedimentary facies allows the identification of several seismic-stratigraphic sequences within the studied successions. Early Cretaceous syn-rift successions (C1 sequence) were deposited in the structural lows near the present-day slope as swamp and marsh facies changing basinwards into turbidites and marine shales. The post-rift Cretaceous sequences (C2, C3 sequences) started with the progradation of the Taranaki delta (C2A-C2D units) followed by sedimentation of the transgressive C3A-E facies accumulated in response to thermal subsidence and high-rates of clastic supply. Extensive shelf conditions prevailed during the deposition of C2 and C3 Cretaceous sequences continued during the Paleogene with deposition of uniform marine shales throughout the basin. Rates of sediment supply substantially decreased during Oligocene prompting the deposition of marine micrite-rich carbonate. Variation in fossil content confirms the occurrence of several cycles of sea level fluctuations and episodic variations in terrigenous input. Organic-rich facies could be associated with the prograding clinoforms of the C2B unit and probably contain, basinward, large amount of gas and oil prone kerogen. The transgressive facies of C2D unit may also contain organic-rich shales basinward and coal near the present day Taranaki shelf. Potential reservoirs are hosted on the C3 transgressive estuarine sandstones. Paleogene mudstones are excellent regional seals for the hydrocarbons generated and trapped in the underlying Late Cretaceous facies.

Hydrocarbon prospectivity of the miocene-pliocene clastic reservoirs, Northern Taranaki basin, New Zealand: integration of petrographic and geophysical studies

In this study, it is aimed to characterize the Early pliocene sandstone (EP-SD) and the Late Miocene-Early Pliocene Mangaa sandstone reservoirs and the efficiency of their sealing cap rocks using the petrographical and petrophysical data of these sandstone zones in northern Taranaki basin, New Zealand. The prospective potential reservoirs were studied using impregnated thin sections, XRD data analysis, and well log data (self-potential, gamma-ray, sonic, density, neutron, shallow\\deep resistivity and PEF) to characterize the reservoir zones, in addition to Mercury intrusion capillary pressure data (MICP) to check the efficiency of some potential seals. The EP-SD and the Mangaa sandstone units are typically poorly consolidated very fine sandstone to siltstone, with porosities averaging 25%. The sands are composed of quartz (38.3–57.4%), with common feldspars (9.9–15.2% plagioclase, and 2.7–6.3% K-feldspars) and up to 31.8% mica. In Albacore-1 well to the north of the Taranaki Basin, the Mangaa formation includes three separate for each of the EP-SD zones (EP-SD1, EP-SD2, and EP-SD3), and the Mangaa sequence (Mangaa-0, Mangaa-1, and Mangaa-2). The thin section studies indicate that, the studied samples are grouped into greywackes, arenites and siltstone microfacies with much lithic fragments and feldspars, sometimes with glauconite pellets. From the XRD data, it is achieved that the mineral composition is dominated by quartz, mica/illite, feldspars, and chlorite. The petrophysical investigation revealed absence of pay zones in the EP-SD zones, and presence of thin pay zone with net thickness 5.79 m and hydrocarbon saturation of about 25.6%. The effective porosities vary between 23.6 and 27.7%, while the shale volume lies between 12.3 and 16.9%. Although the shale content is relatively low, the relatively high API (50–112 API of average 75 API) is contributed by the relatively high K-feldspar content and intercalations with thin siltstone and muddy siltstone beds. Sealing units include the intra-formational seals within the Mangaa sequence, mudstones and fine grained units overlying the Mangaa and further intra-formational mudstones, within the shallower EP-SD units. The efficiency of these seals indicates the capability to trap 16.4–40.6 m gas or 17.4–43.0 m oil which is relatively low in correlation with their efficiency in the central parts of the Taranaki Basin Overlying the primary seals, mudstones of the Giant Foresets Formation provide additional regional seal.

The influence of trap magmatism on the creation of oil and gas deposits

The need to maintain the level of production and an acceptable cost of developing oil and gas fields forces us to rely primarily on the existing reserve, that is, to maximize the potential of traditional oil and gas production regions and adjacent territories - the marginal zones. At the same time, it is necessary to develop unexplored sedimentary complexes at depths of more than 3-5 km. Against this background, it is necessary to highlight a special phenomenon that increases the oil and gas potential of the subsoil associated with trap magmatism. The insufficient level of knowledge of the subsoil makes it possible to predict the discovery of large oil and gas deposits of the traditional type, which will ensure their high profitabilitye. Keywords: trap magmatism; profitability of oil and gas resources; marginal zones; hornfels; transformation of carbonates; rocks of trap formations; regional seals.

Structural analysis and seismic stratigraphy for delineation of Neoproterozoic-Cambrian petroleum system in central and eastern part of Bikaner–Nagaur basin, India

Bikaner–Nagaur basin is located in the northwestern part of India and lies on the rising flank of Punjab platform of Middle Indus basin in Pakistan. Existence of Neoproterozoic-Cambrian petroleum system was confirmed by the exploration activities in the western periphery of the basin, whereas vast areas of central and eastern parts remain unexplored. Knowledge of petroleum system in this unexplored part of the basin is limited due to non-availability of data. Recently, 2525 line km of regional 2D seismic data acquired for the first time by Government of India under National Seismic Program (NSP) unlocks the opportunity for comprehensive understanding of subsurface geology in unexplored part of the basin. Present work aims to interpret recently acquired 2D seismic data and integrate with available surface (outcrop) data, gravity and well data (drilled in western part of basin) for unfolding the petroleum system elements, structural configurations and stratigraphic features in the hitherto central-eastern part of the basin. Two Neoproterozoic-Cambrian hydrocarbon plays: (1) Jodhpur and (2) overlying Bilara/Hanseran Evaporite Group (HEG) were envisaged. Both the plays depicted distinctive seismic characteristics, structural alignment and distribution of reservoir, source and seal. Fluvio-deltaic sandstone within Jodhpur group and shallow marine fractured dolomites within Bilara/HEG showed potential reservoir characteristics whereas organic rich laminated dolomites, stromatolites and argillaceous litho-units within Bilara/HEG group have been predicted as prospective source. The Halite layers within HEG group were considered as effective regional seals. Fault bounded anticlinal structures associated with Cambrian compression have been identified as the main entrapment for hydrocarbon accumulation. The basin witnessed long tectonostratigraphic history with two major compressional phases Structures formed by Cambrian compression are likely to be charged as the time of source maturity and peak expulsion was later, during early Mesozoic period. Overall, the study indicates new opportunities and potential accumulation of hydrocarbon in the unexplored part of the basin.