Visean palaeoincisions as centers of fluid-generation in the Kama coal basin

The paper considers palaeoincisions in the Turnean limestones of the Volga-Ural basin, made by alluvial-deluvial sediments of the Visean age and containing interlayers of coals. Processes occurring in these sediments (catagenic reduction of thickness of coal beds and coal-bearing mudstones, aggressive influence of products of defluidization of coal organic matter on the host rocks, etc.) strengthen the fluid dynamic heterogeneity of intracrustal deposits and contribute to emigration of hydrocarbons (HC). The main oil-and-gas-generating strata in the Carboniferous section include rocks of the Tournaisian stage and the Bobrikovsky horizon of the Viseian stage. Palaeoincisions, along with the area distribution of Viseian coals, can be considered as centers of fluid generation, including liquid and gas HC.

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Pyrogenic nature reservoir rocks as a factor of geofluidodynamic inhomogeneity

Доклады Академии наук ◽

10.31857/s0869-56524893277-280 ◽

2019 ◽

Vol 489 (3) ◽

pp. 277-280

Author(s):

L. A. Abukova ◽

I. F. Yusupova

Keyword(s):

Oil And Gas ◽

Fluid Dynamic ◽

Average Thickness ◽

Coal Basin ◽

Ground Failure ◽

Reservoir Rocks ◽

The Past ◽

Local Areas ◽

Dynamic Structures ◽

Fluid Conductivity

The article considers the Kansko-Achinsky brown coal basin. Huge reserves of solid organic matter (OM) are concentrated in еру Jurassic age sandy-clay sediments. For example, the average thickness of the Borodino field Itatsky layer is 51 m. Attention is drawn to the paleo-centers of heat generation where the coal layers lost (in a whole or partly) their OM. They were destroyed by the underground fires of the past eras. The loss of large masses of the OM in local areas was accompanied by deformations of the coal layers (as well as overlapping ones), appearance of burned and caved ground, failure topographic form (subsidence, funnels, bolsons), and most importantly, the formation of epigenetic cavernosity and pyrogenic reservoir rocks. It is emphasized that the increased fluid conductivity of burned rocks has survived up to the present days. The areas with the burnt rocks are separated into independent fluid dynamic structures with their own parameters (filtration coefficient, water transmissibility, etc.). It has been suggested that pyrogenic reservoir rocks could occur in oil-and-gas basins with coal shale deposits at certain stages of geological development, and at the oil-and-gas generating depths they are able to become reservoirs of catagenic hydrocarbons.

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Geochemical and hydrogeological parameters informativity in oil and gas geology

Georesursy ◽

10.18599/grs.2021.2.21 ◽

2021 ◽

Vol 23 (2) ◽

pp. 214-220

Author(s):

Maria A. Bolshakova ◽

Anna V. Korzun ◽

Antonina V. Stoupakova ◽

Roman S. Sautkin ◽

Anton G. Kalmykov ◽

...

Keyword(s):

Organic Matter ◽

Oil And Gas ◽

Fluid Dynamic ◽

Development Stage ◽

Source Rocks ◽

Salt Deposition ◽

Hydrogeological Parameters ◽

Stage Of Development ◽

Geochemical Studies ◽

Dynamic Connectivity

The article discusses the fundamental possibilities of using the results of geochemical and hydrogeochemical studies of organic matter, oils and waters in oil and gas geology, including for objects at the stage of development. It is shown that complex geochemical studies of oils and waters make it possible to get more correct conclusions about the presence or absence of fluid-dynamic connectivity of different horizons. Studies of organic matter and oils allow (by basin modeling instrument) to understand the contribution of different source rocks to formation of oils of different reservoirs. Hydrogeochemical studies of associated waters and waters used in the reservoir pressure maintenance system in a complex of works not only actively complements the knowledge about the presence or absence of fluid-dynamic connections between reservoirs and production objects, but also make it possible to predict, for example, salt deposition on equipment and in the reservoirs, and therefore allow you to prevent the possibility of unwanted salt deposition. The conclusions are based on the results of comprehensive geological and geochemical studies carried out by the authors for one of the deposits of the Krasnoleninsky arch of Western Siberia, which is at the development stage, as well as on the previous experience of the authors.

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Paleogeothermal and paleotectonic reconstructions based on vitrinite thermometry data (on the example of the upper paleozoic deposits of the Dnieper-Donets depression and adjacent areas of Donbass)

Geofizicheskiy Zhurnal ◽

10.24028/gzh.v43i3.236382 ◽

2021 ◽

Vol 43 (3) ◽

pp. 82-105

Author(s):

A. V. Ivanova ◽

V. B. Gavryltsev

Keyword(s):

Organic Matter ◽

Thermal History ◽

Oil And Gas ◽

Vitrinite Reflectance ◽

Regional Distribution ◽

Distribution Patterns ◽

Tectonic Structures ◽

Upper Paleozoic ◽

Coal Organic Matter ◽

Paleotectonic Reconstructions

The article is devoted to paleogeothermal and paleotectonic reconstructions based on the results of processing the vitrinite reflectance data array of coal organic matter of the Upper Paleozoic sediments from the Don-Dnieper Downwarp (within the Dnieper-Donets Depression and adjacent areas of Donbass). It was found that paleogeothermal parameters changed under the influence of geotectonic, magmatic and lithofacies formation conditions of the Upper Paleozoic deposits. Analysis of changes and regularities distribution of paleogeothermal characteristics made it possible to assess the evolution of the thermal field, changes in the tectonic movements character, to identify the role of volcanism, deep faults geodynamics, lithosphere thickness in the thermal history of the region under study. It is shown that with the help of paleostructural analysis, based on data on the thermal maturity degree of coal organic matter, it is possible to judge the activity changes of tectonic structures in time, the formation sequence, to establish the amplitudes of their mutual displacement and rank according to oil and gas potential. Based on the results of the work, maps of the paleogeothermal gradients distribution and the amplitudes of rock masses vertical displacements were constructed. The presented maps should be considered as a universal information material that can be used to determine the features of the regional distribution of the above parameters, as well as become an important tool in the study of tectonic and thermal history, identification changes trends and distribution patterns of paleogeothermal characteristics.

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Monitoring geological storage of CO2: a new approach

Scientific Reports ◽

10.1038/s41598-021-85346-8 ◽

2021 ◽

Vol 11 (1) ◽

Author(s):

Manzar Fawad ◽

Nazmul Haque Mondol

Keyword(s):

Oil And Gas ◽

Synthetic Data ◽

Leak Detection ◽

Hydrocarbon Exploration ◽

Water Flooding ◽

Storage Site ◽

Gas Reservoirs ◽

New Approach ◽

Coal Beds ◽

Spatial Coverage

AbstractGeological CO2 storage can be employed to reduce greenhouse gas emissions to the atmosphere. Depleted oil and gas reservoirs, deep saline aquifers, and coal beds are considered to be viable subsurface CO2 storage options. Remote monitoring is essential for observing CO2 plume migration and potential leak detection during and after injection. Leak detection is probably the main risk, though overall monitoring for the plume boundaries and verification of stored volumes are also necessary. There are many effective remote CO2 monitoring techniques with various benefits and limitations. We suggest a new approach using a combination of repeated seismic and electromagnetic surveys to delineate CO2 plume and estimate the gas saturation in a saline reservoir during the lifetime of a storage site. This study deals with the CO2 plume delineation and saturation estimation using a combination of seismic and electromagnetic or controlled-source electromagnetic (EM/CSEM) synthetic data. We assumed two scenarios over a period of 40 years; Case 1 was modeled assuming both seismic and EM repeated surveys were acquired, whereas, in Case 2, repeated EM surveys were taken with only before injection (baseline) 3D seismic data available. Our results show that monitoring the CO2 plume in terms of extent and saturation is possible both by (i) using a repeated seismic and electromagnetic, and (ii) using a baseline seismic in combination with repeated electromagnetic data. Due to the nature of the seismic and EM techniques, spatial coverage from the reservoir's base to the surface makes it possible to detect the CO2 plume’s lateral and vertical migration. However, the CSEM low resolution and depth uncertainties are some limitations that need consideration. These results also have implications for monitoring oil production—especially with water flooding, hydrocarbon exploration, and freshwater aquifer identification.

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KEROGEN TYPES OF BAZHENOV FORMATION BASED ON PYROLYSIS DATA AND THEIR COMPARISON WITH OIL PARAMETERS

Oil and Gas Studies ◽

10.31660/0445-0108-2017-5-34-43 ◽

2017 ◽

pp. 34-43

Author(s):

E. E. Oksenoyd ◽

V. A. Volkov ◽

E. V. Oleynik ◽

G. P. Myasnikova

Keyword(s):

Organic Matter ◽

Lower Cretaceous ◽

Alternative Model ◽

Oil And Gas ◽

Upper Jurassic ◽

Gas Content ◽

Basin Modeling ◽

Bazhenov Formation ◽

Gas Bearing

Based on pyrolytic data (3 995 samples from 208 wells) organic matter types of Bazhenov Formation are identified in the central part of Western Siberian basin. Zones of kerogen types I, II, III and mixed I-II and II-III are mapped. Content of sulfur, paraffins, resins and asphaltenes, viscosity, density, temperature and gas content in oils from Upper Jurassic and Lower Cretaceous sediments (3 806 oil pools) are mapped. Oil gradations are identified and distributed. The alternative model of zones of kerogen II and IIS types is presented. The established distributions of organic matter types can be used in basin modeling and in assessment of oil-and-gas bearing prospects.

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Genetic mechanisms and distribution characteristics of overpressures in the Paleogene reservoirs of the Bohai Bay Basin, East China

Energy Exploration & Exploitation ◽

10.1177/0144598717739394 ◽

2018 ◽

Vol 36 (3) ◽

pp. 388-413 ◽

Cited By ~ 3

Author(s):

Fanghao Xu ◽

Jiaju Liang ◽

Guosheng Xu ◽

Haifeng Yuan ◽

Yong Liu

Keyword(s):

Organic Matter ◽

Oil And Gas ◽

Bohai Bay ◽

Hydrocarbon Generation ◽

Distribution Characteristics ◽

Well Drilling ◽

The Third ◽

Genetic Mechanisms ◽

Shahejie Formation ◽

Tectonic Framework

The Bohai Bay region is a primary accumulation area of oil and gas in offshore China, in which overpressure commonly occurs in the Paleogene strata; the analysis on distribution characteristics and genetic mechanisms of the overpressure would provide geologic evidences for making plans of well drilling and logging as well as oil and gas exploitation; additionally, it could lay the geological foundation for studying how overpressure controlled hydrocarbon accumulation. Based on research, the overpressure of the study area starts from the second member of the Dongying Formation and ends in the third member of the Shahejie Formation. The distribution of overpressure is mainly controlled by the sag–salient tectonic framework within the basin, which means overpressure mainly develops in sags or slopes; however, high areas stay normal pressured. In the study area, pressure develops around Bozhong Sag and in northern Liaodong Bay reaches the peak. The genetic mechanisms of overpressures in the Paleogene reservoirs are mainly disequilibrium compaction, hydrocarbon generation of the organic matter, fluid charging, and transmission or the superimposition of the former two. Different strata have different genetic mechanisms of overpressure. The chief genetic mechanisms for the generation of overpressure of the Dongying Formation are disequilibrium compaction while the genesis of the formation of overpressure in the Shahejie Formation is more complicated in some extent. The first member of the Shahejie Formation dominated by disequilibrium compaction and hydrocarbon generation of the organic matter plays a supplemental role, while the second member of the Shahejie Formation, as the primary reservoir strata, is dominated by fluid charging and transmission, and the third member of the Shahejie Formation is the main source rock interval; its overpressure is closely related to hydrocarbon generation. Each contribution ratio for overpressure forming by different genetic mechanisms has been judged and figured out quantitatively according to geological, geophysical, and geochemical characteristics of the target strata.

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Investigation of Proppant Distributions in Rock Fractures With Applications to Hydraulic Fracturing

10.1115/fedsm2021-65833 ◽

2021 ◽

Author(s):

Amir A. Mofakham ◽

Farid Rousta ◽

Dustin M. Crandall ◽

Goodarz Ahmadi

Keyword(s):

Fluid Flow ◽

Hydraulic Fracturing ◽

Oil And Gas ◽

Fluid Dynamic ◽

Rock Fracture ◽

Experimental Investigations ◽

Rock Fractures ◽

Fracture Geometry ◽

Injection Process ◽

Fracking Fluid

Abstract Hydraulic fracturing or fracking is a procedure used extensively by oil and gas companies to extract natural gas or petroleum from unconventional sources. During this process, a pressurized liquid is injected into wellbores to generate fractures in rock formations to create more permeable pathways in low permeability rocks that hold the oil. To keep the rock fractures open after removing the high pressure, proppant, which typically are sands with different shapes and sizes, are injected simultaneously with the fracking fluid to spread them throughout rock fractures. The extraction productivity from shale reservoirs is significantly affected by the performance and quality of the proppant injection process. Since these processes occur under the ground and in the rock fractures, using experimental investigations to examine the process is challenging, if not impossible. Therefore, employing numerical tools for analyzing the process could provide significant insights leading to the fracking process improvement. Accordingly, in this investigation, a 4-way coupled Computational Fluid Dynamic and Discrete Element Method (CFD-DEM) code was used to simulate proppant transport into a numerically generated realistic rock fracture geometry. The simulations were carried out for a sufficiently long period to reach the fractures’ steady coverage by proppant. The proppant fracture coverage is a distinguishing factor that can be used to assess the proppant injection process quality. A series of simulations with different proppant sizes as well as various fracking fluid flow rates, were performed. The corresponding estimated fracture coverages for different cases were compared. The importance of proppant size as well as the fluid flow rate on the efficiency of the proppant injection process, were evaluated and discussed.

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Study on the distribution of extractable organic matter in pores of lacustrine shale: An example of Zhangjiatan Shale from the Upper Triassic Yanchang Formation, Ordos Basin, China

Interpretation ◽

10.1190/int-2016-0124.1 ◽

2017 ◽

Vol 5 (2) ◽

pp. SF109-SF126 ◽

Cited By ~ 7

Author(s):

Yuxi Yu ◽

Xiaorong Luo ◽

Ming Cheng ◽

Yuhong Lei ◽

Xiangzeng Wang ◽

...

Keyword(s):

Organic Matter ◽

Oil And Gas ◽

Storage Capacity ◽

Ordos Basin ◽

Organic Content ◽

Capacity Control ◽

Yanchang Formation ◽

Geochemical Characterization ◽

Extractable Organic Matter

Shale oil and gas have been discovered in the lacustrine Zhangjiatan Shale in the southern Ordos Basin, China. To study the distribution of extractable organic matter (EOM) in the Zhangjiatan Shale ([Formula: see text] ranges from 1.25% to 1.28%), geochemical characterization of core samples of different lithologies, scanning electron microscope observations, low-pressure [Formula: see text] and [Formula: see text] adsorption, and helium pycnometry were conducted. The content and saturation of the EOM in the pores were quantitatively characterized. The results show that the distribution of the EOM in the shale interval is heterogeneous. In general, the shale layers have a higher EOM content and saturation than siltstone layers. The total organic content and the original storage capacity control the EOM content in the shale layers. For the siltstone layers, the EOM content is mainly determined by the original storage capacity. On average, 75% of the EOM occurs in the mesopores, followed by 14% in the macropores, and 11% in the micropores. The EOM saturation in the pores decreases with the increase in pore diameter. The distribution of EOM in the shale pores is closely related to the pore type. Micropores and mesopores developed in the kerogens and pyrobitumens and the clay-mineral pores coated with organic matter are most favorable for EOM retention and charging.

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

The APPEA Journal ◽

10.1071/aj02006 ◽

2003 ◽

Vol 43 (1) ◽

pp. 117 ◽

Cited By ~ 18

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.

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THE USE OF COALS AS INDICATORS OF THE OCCURRENCE OF OIL AND GAS

The APPEA Journal ◽

10.1071/aj69007 ◽

1970 ◽

Vol 10 (1) ◽

pp. 35 ◽

Cited By ~ 2

Author(s):

J. D. Brooks

Keyword(s):

Organic Matter ◽

Carbon Content ◽

Oil And Gas ◽

Sedimentary Basin ◽

Total Carbon ◽

Maximum Temperature ◽

Mineral Matter ◽

Hydrocarbon Generation ◽

Oil Companies ◽

Upper Limit

Petroleum hydrocarbons are not normal constituents of recent sediments but only appear when a certain stage of diagenesis is reached, through deeper burial. An investigation of the mechanism of formation of oil and gas has shown that an indication of the generation of oil in a sedimentary basin can be obtained by an examination of coals or coaly material encountered during drilling.Coals form a continuous diagenetic and metamorphic series beginning with peat and ending with graphite. Peat and brown coal contain the same type of hydrocarbons as are present in land plants but the composition of coal hydrocarbons changes abruptly in the sub-bituminous to high-volatile bituminous coal range. This is because petroleum-type hydrocarbons are formed at this stage from precursors which are components of waxy leaf cuticles, pollen and spore coatings, by chemical reactions in which oxygen groups are removed from long-chain acids, alcohols and ester waxes. Most Australian oil occurrences are associated with coal-bearing sediments and it appears likely that they are formed at the same stage of alteration, from such land plant residues, finely disseminated in shales and siltstones.The diagenetic changes in coal composition are caused by the increasing temperature accompanying deeper burial, and the composition of a coal, whatever its present depth, is an indication of the maximum temperature to which it has been subjected. The determination of carbon content, reflectivity and other properties of coal samples provided by a number of oil companies, together with laboratory experiments in which petroleum-type hydrocarbons were generated by artificial diagenesis of coal components, indicated that hydrocarbon generation takes place only when the carbon content of the coals approaches 80 percent. In sedimentary basins in Australia the petroleum generation zone occurs at depths varying from 5,500 to greater than 11,000ft., depending upon present or past geothermal gradient.In addition to this lower limit of diagenesis, it has long been maintained that a relation exists (the Carbon Ratio theory) between the likely occurrence of oil and gas reservoirs in a sedimentary basin and the degree of metamorphism of coal if present. The theory sets an upper limit of alteration of organic matter, and states that oil reservoirs are unlikely to occur in areas or at depths in a basin where the 'fixed-carbon' of the coals is greater than about 65 percent (equivalent to a coal of about 85 percent total carbon — dry, mineral-matter free). The Gid-gealpa-Moomba area appears to be a part of the Cooper Basin in which the organic matter is close to this upper limit of metamorphism. The carbon content of the coal at Gidgealpa, associated with gas and light hydrocarbons, is 85-86 percent whereas that at Moomba, associated with dry gas, is higher at approximately 89 percent.Ihus the properties of coal samples encountered during drilling can provide valuable clues for the petroleum geologist in the search for further oil and gas reserves.

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