Hydrocarbon potential and prospects for exploration of Eastern Arctic oil and gas deposits

2021 ◽  
pp. 85-92
Author(s):  
V. Yu. Kerimov ◽  
◽  
E. A. Lavrenova ◽  
R. N. Mustaev ◽  
Yu. V. Shcherbina ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Sedimentary Basins ◽  
Space Time ◽  
Source Rocks ◽  
Hydrocarbon Potential ◽  
Basin Modeling ◽  
Single Model ◽  
Gas Reservoirs ◽  
Oil Hydrocarbons ◽  
Potential Traps

Conditions for the formation of hydrocarbon systems and prospects for searching for accumulations of oil and gas in the waters of the Eastern Arctic are considered. Significant hydrocarbon potential is predicted in the sedimentary basins of this region. All known manifestations of oil hydrocarbons are installed on land adjacent to the south, as well as on the east of the shelf. The East Arctic waters are included in a single model in order to perform an adequate comparative analysis of the evolution of hydrocarbon systems. The purpose of the research was to build space-time digital models of sedimentary basins and hydrocarbon systems, and to quantify the volume of generation, migration, and accumulation of hydrocarbons for the main horizons of source rocks. To achieve this goal, a spatiotemporal numerical basin simulation was carried out, based on which the distribution of probable hydrocarbon systems was determined and further analyzed. Following to the data obtained the most probable HC accumulation zones and types of fluids contained in potential traps were predicted. Keywords: numerical space-time basin modeling; modeling of hydrocarbon systems; evidence of oil and gas presence; Eastern Arctic; elements of hydrocarbon systems; oil and gas reservoirs; migration; accumulation; perspective objects

scholarly journals Assessment of the hydrocarbon potential of the Bering Sea

2021 ◽  
Vol 63 (5) ◽  
pp. 42-56
Author(s):  
E. A. Lavrenova ◽  
S. A. Guryanov ◽  
V. Yu. Kerimov
Keyword(s):  
Bering Sea ◽  
Oil And Gas ◽  
Sedimentary Basins ◽  
Water Area ◽  
Source Rocks ◽  
Hydrocarbon Potential ◽  
Accumulation Coefficient ◽  
Geochemical Studies ◽  
Factual Data ◽  
The Bering Sea

Background. The issues of hydrocarbon (HC) forecasting and prospecting on sea shelves remain relevant. In this paper, an experience of assessing the hydrocarbon potential of the Bering Sea using the method of basin modelling is demonstrated.Aim. To assess the hydrocarbon potential of the Bering Sea and to identify prospective areas on the basis of a comprehensive analysis of factual data and the results of modelling sedimentary basins and hydrocarbon systems.Materials and methods. A large volume of geological and geophysical materials and the results of geochemical studies were analysed. Modelling was carried out based on factual data, which made it possible to design space-time digital models of sedimentary basins and hydrocarbon (HC) systems for the main horizons of oil and gas source rocks. Geochemical and lithological studies, as well as modelling, were performed using the Schlumberger PetroMod and QGIS software. A smallscale modelling of sedimentary basins and hydrocarbon systems of the region under study was conducted. In the process of preparing the input data for modelling, a number of necessary structural constructions, lithological-paleogeographic and paleodynamic reconstructions and other special studies were performed, which made it possible to determine the modelling boundary conditions.Results. The studied hydrocarbon systems of the Bering Sea differ in the area and size of the generation source, and consequently, in the volumes of generated hydrocarbons. The maximum specific (per unit area of the generation-accumulation hydrocarbon system (GAHS)) volumes of generated hydrocarbons are predicted in the Mainitsko-Sobolkovskaya GAHS of the East Anadyr depression, the Nikolaevskaya Mainitsko-Sobolkovskaya and Mainitsko-Sobolkovskaya of the Lagoon trough. However, even the most promising areas are attributed to the V category due to the low quality of kerogen and a low accumulation coefficient.Conclusion. In the water area of the Anadyr trough, prospective areas were identified. Two promising levels of oil and gas potential were determined. A quantitative assessment of the hydrocarbon potential of the GAHS was carried out.

Research for the Upstream Petroleum Sector: The Crown Research Institute Concept

1995 ◽  
Vol 13 (2-3) ◽  
pp. 245-252
Author(s):  
J M Beggs
Keyword(s):  
New Zealand ◽  
Oil And Gas ◽  
Sedimentary Basins ◽  
Source Rocks ◽  
Publicly Funded ◽  
Petroleum Systems ◽  
Oil And Gas Resources ◽  
Petroleum Sector ◽  
Geological Sciences ◽  
Research Institute

New Zealand's scientific institutions have been restructured so as to be more responsive to the needs of the economy. Exploration for and development of oil and gas resources depend heavily on the geological sciences. In New Zealand, these activities are favoured by a comprehensive, open-file database of the results of previous work, and by a historically publicly funded, in-depth knowledge base of the extensive sedimentary basins. This expertise is now only partially funded by government research contracts, and increasingly undertakes contract work in a range of scientific services to the upstream petroleum sector, both in New Zealand and overseas. By aligning government-funded research programmes with the industry's knowledge needs, there is maximum advantage in improving the understanding of the occurrence of oil and gas resources. A Crown Research Institute can serve as an interface between advances in fundamental geological sciences, and the practical needs of the industry. Current publicly funded programmes of the Institute of Geological and Nuclear Sciences include a series of regional basin studies, nearing completion; and multi-disciplinary team studies related to the various elements of the petroleum systems of New Zealand: source rocks and their maturation, migration and entrapment as a function of basin structure and tectonics, and the distribution and configuration of reservoir systems.

scholarly journals Fluid geochemistry of the Jurassic Ahe Formation and implications for reservoir formation in the Dibei area, Tarim Basin, northwest China

2018 ◽  
Vol 36 (4) ◽  
pp. 801-819 ◽  
Author(s):  
Shuangfeng Zhao ◽  
Wen Chen ◽  
Zhenhong Wang ◽  
Ting Li ◽  
Hongxing Wei ◽  
...  
Keyword(s):  
Natural Gas ◽  
Tarim Basin ◽  
Oil And Gas ◽  
Northwest China ◽  
Source Rocks ◽  
Coal Measure ◽  
Hydrocarbon Generation ◽  
Gas Reservoirs ◽  
Isotopic Analyses ◽  
Jurassic Coal

The condensate gas reservoirs of the Jurassic Ahe Formation in the Dibei area of the Tarim Basin, northwest China are typical tight sandstone gas reservoirs and contain abundant resources. However, the hydrocarbon sources and reservoir accumulation mechanism remain debated. Here the distribution and geochemistry of fluids in the Ahe gas reservoirs are used to investigate the formation of the hydrocarbon reservoirs, including the history of hydrocarbon generation, trap development, and reservoir evolution. Carbon isotopic analyses show that the oil and natural gas of the Ahe Formation originated from different sources. The natural gas was derived from Jurassic coal measure source rocks, whereas the oil has mixed sources of Lower Triassic lacustrine source rocks and minor amounts of coal-derived oil from Jurassic coal measure source rocks. The geochemistry of light hydrocarbon components and n-alkanes shows that the early accumulated oil was later altered by infilling gas due to gas washing. Consequently, n-alkanes in the oil are scarce, whereas naphthenic and aromatic hydrocarbons with the same carbon numbers are relatively abundant. The fluids in the Ahe Formation gas reservoirs have an unusual distribution, where oil is distributed above gas and water is locally produced from the middle of some gas reservoirs. The geochemical characteristics of the fluids show that this anomalous distribution was closely related to the dynamic accumulation of oil and gas. The period of reservoir densification occurred between the two stages of oil and gas accumulation, which led to the early accumulated oil and part of the residual formation water being trapped in the tight reservoir. After later gas filling into the reservoir, the fluids could not undergo gravity differentiation, which accounts for the anomalous distribution of fluids in the Ahe Formation.

scholarly journals Studies on the onshore hydrocarbon potential in East Greenland 1986-87: field work from 72° to 74°N

1987 ◽  
Vol 135 ◽  
pp. 72-81
Author(s):  
C Marcussen ◽  
F.G Christiansen ◽  
P.-H Larsen ◽  
H Olsen ◽  
S Piasecki ◽  
...  
Keyword(s):  
Thermal History ◽  
Sedimentary Basins ◽  
Field Work ◽  
Source Rocks ◽  
Hydrocarbon Potential ◽  
East Greenland ◽  
The North ◽  
Hydrocarbon Traps ◽  
Subsidence History ◽  
Tectonic Study

A study of the onshore hydrocarbon potential of central and northem East Greenland was initiated in 1986. Field work was carried out from early July to mid August covering the region between Kong Oscar Fjord and Kejser Franz Joseph Fjord (fig. 1). In 1987 field activities will continue further to the north, eventually reaching Danmarkshavn (77°N). The programme is a continuation of the 1982-83 investigations in Jameson Land (Surlyk, 1983; Surlyk et al., 1984a) and is part of a regional programme comprising petroleum geological studies of all sedimentary basins in Greenland (Larsen & Marcussen, 1985; Larsen, 1986). The aim of the two-year field study followed by laboratory analyses is: (1) to study the presence and distribution of potential hydrocarbon source rocks in the region; (2) to evaluate the thermal history and maturity pattern of the region including the thermal effect of Tertiary intrusions and volcanics; (3) to make a stratigraphic, sedimentological and tectonic study of the region with special emphasis on subsidence history, reservoir formation and potential hydrocarbon traps.

scholarly journals GEOCHEMICAL AND GEOSTATISTICAL ASSESSMENT OF CRETACEOUS COALS AND SHALES IN SOME NIGERAIN SEDIMENTARY BASINS FOR THEIR HYDROCARBON PRONESS AND MATURITY LEVELS

2020 ◽  
Vol 1 (2) ◽  
Keyword(s):  
Source Rock ◽  
Oil And Gas ◽  
Linear Regression Analysis ◽  
Sedimentary Basins ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Good Source ◽  
Type Iii ◽  
Limit Value ◽  
The Impact

The Rock–Eval pyrolysis and LECO analysis for 9 shale and 12 coal samples, as well as, geostatistical analysis have been used to investigate source rock characteristics, correlation between the assessed parameters (QI, BI, S1, S2, S3, HI, S1 + S2, OI, PI, TOC) and the impact of changes in the Tmax on the assessed parameters in the Cretaceous Sokoto, Anambra Basins and Middle Benue Trough of northwestern, southeastern and northcentral Nigeria respectively. The geochemical results point that about 97% of the samples have TOC values greater than the minimum limit value (0.5 wt %) required to induce hydrocarbon generation from source rocks. Meanwhile, the Dukamaje and Taloka shales and Lafia/Obi coal are found to be fair to good source rock for oil generation with slightly higher thermal maturation. The source rocks are generally immature through sub-mature to marginal mature with respect to the oil and gas window, while the potential source rocks from the Anambra Basin are generally sub-mature grading to mature within the oil window. The analyzed data were approached statistically to find some relations such as factors, and clusters concerning the examination of the source rocks. These factors were categorized into type of organic matter and organic richness, thermal maturity and hydrocarbon potency. In addendum, cluster analysis separated the source rocks in the study area into two groups. The source rocks characterized by HI >240 (mg/g), TOC from 58.89 to 66.43 wt %, S1 from 2.01 to 2.54 (mg/g) and S2 from 148.94 to 162.52 (mg/g) indicating good to excellent source rocks with kerogen of type II and type III and are capable of generating oil and gas. Followed by the Source rocks characterized by HI <240 (mg/g), TOC from 0.94 to 36.12 wt%, S1 from 0.14 to 0.72 (mg/g) and S2 from 0.14 to 20.38 (mg/g) indicating poor to good source rocks with kerogen of type III and are capable of generating gas. Howeverr, Pearson’s correlation coefficient and linear regression analysis shows a significant positive correlation between TOC and S1, S2 and HI and no correlation between TOC and Tmax, highly negative correlation between TOC and OI and no correlation between Tmax and HI. Keywords- Cretaceous, Geochemical, Statistical, Cluster; Factor analyses.

scholarly journals Modeling of hydrocarbon systems and quantitative assessment of the hydrocarbon potential of Eastern Arctic seas

2021 ◽  
Vol 63 (4) ◽  
pp. 23-38
Author(s):  
E. A. Lavrenova ◽  
Yu. V. Shcherbina ◽  
R. A. Mamedov
Keyword(s):  
Quantitative Assessment ◽  
Oil And Gas ◽  
Sedimentary Basins ◽  
Water Area ◽  
Hydrocarbon Potential ◽  
Arctic Seas ◽  
Arctic Water ◽  
Oil Companies ◽  
Flow Maps ◽  
Assessment Factor

Background. Three prospective sedimentary complexes — Aptian-Upper Cretaceous, Paleogene and Neogene — are predicted in the waters of the Eastern Arctic seas. Here, the search for oil and gas is associated with harsh Arctic conditions at sea, as well as with high geological risks and significant expenditures under the conditions of poor knowledge of the region. In this regard, the localisation of prospecting drilling objects and the assessment of the geological risks of deposit discovery should be carried out.Aim. To assess geological risks and to determine the probability of discovering oil and gas fields, as well as to identify prospective areas for licensing and exploration in the water areas of the Eastern Arctic.Materials and methods. Structural and heat flow maps along with the results of geochemical analysis, as well as typical terrestrial sections were used as initial materials. Using the method of basin analysis, the modelling of generation-accumulation hydrocarbon systems (GAHS) and the quantitative assessment of its hydrocarbon potential in the Eastern Arctic water area was carried out. The assessment of geological risks and the probability of field discovery was performed using the conventional methodology widely applied by oil companies.Results. The GAHS modelling using a variation approach showed that, regardless of the kerogen type, with average values of Сorg in sediments, potential oil-and-gas source strata (OGSS) were capable of saturating the prospective objects with hydrocarbons. The “OGSS assessment” factor was determined as “encouraging” (0.7). Active geodynamic regime and the manifestation of several folding phases within the study area provided favourable conditions for the formation of anticlinaltraps in sedimentary basins. However, the cap rock quality rating was assessed as “neutral” (0.5). The overall risk for the “Trap assessment” factor was estimated based on the minimum criterion of 0.5.Conclusion. The most prospective areas recommended for licensing were selected, and the recommendations for further geological exploration work in these areas were given in order to clarify their hydrocarbon potential and reduce geological risks.

NEW PETROLEUM MODELS IN THE PEDIRKA BASIN, NORTHERN TERRITORY, AUSTRALIA

2002 ◽  
Vol 42 (1) ◽  
pp. 259 ◽  
Author(s):  
G.J. Ambrose ◽  
K. Liu ◽  
I. Deighton ◽  
P.J. Eadington ◽  
C.J. Boreham
Keyword(s):  
Oil And Gas ◽  
South Australia ◽  
Sedimentary Basins ◽  
Poor Quality ◽  
Northern Territory ◽  
Early Jurassic ◽  
Source Rocks ◽  
Late Triassic ◽  
Hydrocarbon Expulsion ◽  
Migration Pathways

The northern Pedirka Basin in the Northern Territory is sparsely explored compared with its southern counterpart in South Australia. Only seven wells and 2,500 km of seismic data occur over a prospective area of 73,000 km2 which comprises three stacked sedimentary basins of Palaeozoic to Mesozoic age. In this area three petroleum systems have potential related to important source intervals in the Early Jurassic Eromanga Basin (Poolowanna Formation), the Triassic Simpson Basin (Peera Peera Formation) and Early Permian Pedirka Basin (Purni Formation). They are variably developed in three prospective depocentres, the Eringa Trough, the Madigan Trough and the northern Poolowanna Trough. Basin modelling using modern techniques indicate oil and gas expulsion responded to increasing early Late Cretaceous temperatures in part due to sediment loading (Winton Formation). Using a composite kinetic model, oil and gas expulsion from coal rich source rocks were largely coincident at this time, when source rocks entered the wet gas maturation window.The Purni Formation coals provide the richest source rocks and equate to the lower Patchawarra Formation in the Cooper Basin. Widespread well intersections indicate that glacial outwash sandstones at the base of the Purni Formation, herein referred to as the Tirrawarra Sandstone equivalent, have regional extent and are an important exploration target as well as providing a direct correlation with the prolific Patchawarra/Tirrawarra petroleum system found in the Cooper Basin.An integrated investigation into the hydrocarbon charge and migration history of Colson–1 was carried out using CSIRO Petroleum’s OMI (Oil Migration Intervals), QGF (Quantitative Grain Fluorescence) and GOI (Grains with Oil Inclusions) technologies. In the Early Jurassic Poolowanna Formation between 1984 and 2054 mRT, elevated QGF intensities, evidence of oil inclusions and abundant fluorescing material trapped in quartz grains and low displacement pressure measurements collectively indicate the presence of palaeo-oil and gas accumulation over this 70 m interval. This is consistent with the current oil show indications such as staining, cut fluorescence, mud gas and surface solvent extraction within this reservoir interval. Multiple hydrocarbon migration pathways are also indicated in sandstones of the lower Algebuckina Sandstone, basal Poolowanna Formation and Tirrawarra Sandstone equivalent. This is a significant upgrade in hydrocarbon prospectivity, given previous perceptions of relatively poor quality and largely immature source rocks in the Basin.Conventional structural targets are numerous, but the timing of hydrocarbon expulsion dictates that those with an older drape and compaction component will be more prospective than those dominated by Tertiary reactivation which may have resulted in remigration or leakage. Preference should also apply to those structures adjacent to generative source kitchens on relatively short migration pathways. Early formed stratigraphic traps at the level of the Tirrawarra Sandstone equivalent and Poolowanna Formation are also attractive targets. Cyclic sedimentation in the Poolowanna Formation results in two upward fining cycles which compartmentalise the sequence into two reservoir–seal configurations. Basal fluvial sandstone reservoirs grade upwards into topset shale/coal lithologies which form effective semi-regional seals. Onlap of the basal cycle onto the Late Triassic unconformity offers opportunities for stratigraphic entrapment.

COAL AS A SOURCE OF OIL AND GAS: A CASE STUDY FROM THE BASS BASIN, AUSTRALIA

2003 ◽  
Vol 43 (1) ◽  
pp. 117 ◽  
Author(s):  
C.J. Boreham ◽  
J.E. Blevin ◽  
A.P. Radlinski ◽  
K.R. Trigg
Keyword(s):  
Organic Matter ◽  
Oil And Gas ◽  
Middle Eocene ◽  
Vitrinite Reflectance ◽  
Mineral Resources ◽  
Sedimentary Basins ◽  
Source Rocks ◽  
Gas Generation ◽  
Australian Context ◽  
Effective Source

Only a few published geochemical studies have demonstrated that coals have sourced significant volumes of oil, while none have clearly implicated coals in the Australian context. As part of a broader collaborative project with Mineral Resources Tasmania on the petroleum prospectivity of the Bass Basin, this geochemical study has yielded strong evidence that Paleocene–Eocene coals have sourced the oil and gas in the Yolla, Pelican and Cormorant accumulations in the Bass Basin.Potential oil-prone source rocks in the Bass Basin have Hydrogen Indices (HIs) greater than 300 mg HC/g TOC. The coals within the Early–Middle Eocene succession commonly have HIs up to 500 mg HC/g TOC, and are associated with disseminated organic matter in claystones that are more gas-prone with HIs generally less than 300 mg HC/g TOC. Maturity of the coals is sufficient for oil and gas generation, with vitrinite reflectance (VR) up to 1.8 % at the base of Pelican–5. Igneous intrusions, mainly within Paleocene, Oligocene and Miocene sediments, produced locally elevated maturity levels with VR up to 5%.The key events in the process of petroleum generation and migration from the effective coaly source rocks in the Bass Basin are:the onset of oil generation at a VR of 0.65% (e.g. 2,450 m in Pelican–5);the onset of oil expulsion (primary migration) at a VR of 0.75% (e.g. 2,700–3,200 m in the Bass Basin; 2,850 m in Pelican–5);the main oil window between VR of 0.75 and 0.95% (e.g. 2,850–3,300 m in Pelican–5); and;the main gas window at VR >1.2% (e.g. >3,650 m in Pelican–5).Oils in the Bass Basin form a single oil population, although biodegradation of the Cormorant oil has resulted in its statistical placement in a separate oil family from that of the Pelican and Yolla crudes. Oil-to-source correlations show that the Paleocene–Early Eocene coals are effective source rocks in the Bass Basin, in contrast to previous work, which favoured disseminated organic matter in claystone as the sole potential source kerogen. This result represents the first demonstrated case of significant oil from coal in the Australian context. Natural gases at White Ibis–1 and Yolla–2 are associated with the liquid hydrocarbons in their respective fields, although the former gas is generated from a more mature source rock.The application of the methodologies used in this study to other Australian sedimentary basins where commercial oil is thought to be sourced from coaly kerogens (e.g. Bowen, Cooper and Gippsland basins) may further implicate coal as an effective source rock for oil.

scholarly journals Formation conditions and evolution of oil and gas source strata of the Laptev sea shelf ore and gas province

2021 ◽  
pp. 46-59
Author(s):  
V. Yu. Kerimov ◽  
Yu. V. Shcherbina ◽  
A. A. Ivanov
Keyword(s):  
Oil And Gas ◽  
Numerical Models ◽  
Sedimentary Basins ◽  
Water Area ◽  
Source Rocks ◽  
Gas Content ◽  
Laptev Sea ◽  
Hydrocarbon Generation ◽  
Gas Source ◽  
The Laptev Sea

Introduction. To date, no unified well-established concepts have been developed regarding the oil and gas geological zoning of the Laptev Sea shelf, as well as other seas of the Eastern Arctic. Different groups of researchers define this region either as an independently promising oil and gas region [7, 8], or as a potential oil and gas basin [1].Aim. To construct spatio-temporal digital models of sedimentary basins and hydrocarbon systems for the main horizons of oil and gas source rocks. A detailed analysis of information on oil and gas content, the gas chemical study of sediments, the characteristics of the component composition and thermal regime of the Laptev sea shelf water area raises the question on the conditions for the formation and evolution of oil and gas source strata within the studied promising oil and gas province. The conducted research made it possible to study the regional trends in oil and gas content, the features of the sedimentary cover formation and the development of hydrocarbon systems in the area under study.Materials and methods. The materials of production reports obtained for individual large objects in the water area were the source of initial information. The basin analysis was based on a model developed by Equinor specialists (Somme et al., 2018) [14—17], covering the time period from the Triassic to Paleogene inclusive and taking into account the plate-tectonic reconstructions. The resulting model included four main sedimentary complexes: pre-Aptian, Apt-Upper Cretaceous, Paleogene, and Neogene-Quaternary.Results. The calculation of numerical models was carried out in two versions with different types of kerogen from the oil and gas source strata corresponding to humic and sapropel organic matter. The results obtained indicated that the key factor controlling the development of hydrocarbon systems was the sinking rate of the basins and the thickness of formed overburden complexes, as well as the geothermal field of the Laptev Sea.Conclusion. The analysis of the results obtained allowed the most promising research objects to be identified. The main foci of hydrocarbon generation in the Paleogene and Neogene complexes and the areas of the most probable accumulation were determined. Significant hydrocarbon potential is expected in the Paleogene clinoforms of the Eastern Arctic.

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