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Academic literature on the topic 'Source rock reservoir'

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Published: 10 December 2022
Last updated: 28 January 2023

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Journal articles on the topic "Source rock reservoir"

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Al-Ameri, Thamer K., Amer Jassim Al-Khafaji, and John Zumberge. "Petroleum system analysis of the Mishrif reservoir in the Ratawi, Zubair, North and South Rumaila oil fields, southern Iraq." GeoArabia 14, no. 4 (October 1, 2009): 91–108. http://dx.doi.org/10.2113/geoarabia140491.

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ABSTRACT Five oil samples reservoired in the Cretaceous Mishrif Formation from the Ratawi, Zubair, Rumaila North and Rumaila South fields have been analysed using Gas Chromatography – Mass Spectroscopy (GC-MS). In addition, fifteen core samples from the Mishrif Formation and 81 core samples from the Lower Cretaceous and Upper Jurassic have been subjected to source rock analysis and palynological and petrographic description. These observations have been integrated with electric wireline log response. The reservoirs of the Mishrif Formation show measured porosities up to 28% and the oils are interpreted as being sourced from: (1) Type II carbonate rocks interbedded with shales and deposited in a reducing marine environment with low salinity based on biomarkers and isotopic analysis; (2) Upper Jurassic to Lower Cretaceous age based on sterane ratios, analysis of isoprenoids and isotopes, and biomarkers, and (3) Thermally mature source rocks, based on the biomarker analysis. The geochemical analysis suggests that the Mishrif oils may have been sourced from the Upper Jurassic Najma or Sargelu formations or the Lower Cretaceous Sulaiy Formation. Visual kerogen assessment and source rock analysis show the Sulaiy Formation to be a good quality source rock with high total organic carbon (up to 8 wt% TOC) and rich in amorphogen. The Lower Cretaceous source rocks were deposited in a suboxic-anoxic basin and show good hydrogen indices. They are buried at depths in excess of 5,000 m and are likely to have charged Mishrif reservoirs during the Miocene. The migration from the source rock is likely to be largely vertical and possibly along faults before reaching the vuggy, highly permeable reservoirs of the Mishrif Formation. Structural traps in the Mishrif Formation reservoir are likely to have formed in the Late Cretaceous.
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Hao, Hui Zhi, and Li Juan Tan. "The Characteristic of Oil and Gas Accumulation and Main Factors of Reservoir Enrichment in SZ36-1 Region." Applied Mechanics and Materials 737 (March 2015): 859–62. http://dx.doi.org/10.4028/www.scientific.net/amm.737.859.

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The hydrocarbon reservoirs which have been found in SZ36-1 region are located in Liaoxi low uplift and dominated by structural traps. The principle source rock is the first and the third member of the Neogen Shahejie Formation and the main reservoir type is delta sand body which mainly located in the second member of Shahejie Formation. Oil reservoirs are mostly in normal pressure and are possess characteristic of late hydrocarbon accumulation. Hydrocarbon accumulation is mainly controlled by fault,reservoir-cap rock combination, and petroleum migration pathways. Lateral distribution of hydrocarbon reservoirs is mostly controlled by reservoir rocks, while the vertical distribution is controlled by fault.
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Tang, Youjun, Meijun Li, Qiuge Zhu, Daxiang He, Xingchao Jiang, Hong Xiao, Junfeng Shan, Wujiang Kang, Junying Leng, and Wenqiang Wang. "Geochemical characteristics and origin of hydrocarbons in the Mesoproterozoic reservoirs in the Liaoxi Depression, NE China." Energy Exploration & Exploitation 38, no. 2 (July 12, 2019): 333–47. http://dx.doi.org/10.1177/0144598719862922.

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Oil reservoirs have been discovered in the Mesoproterozoic strata in the Liaoxi Depression, NE China. In order to determine the source of oil shows of the Mesoproterozoic Gaoyuzhuang Formation and their organic geochemical characteristics, eight source rocks and reservoir cores from the Mesoproterozoic Gaoyuzhuang Formation and four source rocks from the overlying Middle Jurassic Haifanggou Formation were geochemically analysed. The distribution patterns of normal alkanes, acyclic isoprenoids, hopanes, steranes and triaromatic steroids of the Mesoproterozoic hydrocarbons from Well N-1 are consistent with those of source rock extracts from the Mesoproterozoic Gaoyuzhuang Formation in the Well L-1. The molecular marker compositions of source rock extracts from the overlying Middle Jurassic Haifanggou Formation are distinctively different from those of the Mesoproterozoic hydrocarbons. The results suggest that the Mesoproterozoic source rocks have significant petroleum generation potential. The Mesoproterozoic paleo-reservoir may be prospecting exploration targets in the Liaoxi Depression, NE China.
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Peng, Biao, Lulu Zhang, Jianfeng Li, Tiantian Chang, and Zheng Zhang. "Multi-Type Hydrocarbon Accumulation Mechanism in the Hari Sag, Yingen Ejinaqi Basin, China." Energies 15, no. 11 (May 27, 2022): 3968. http://dx.doi.org/10.3390/en15113968.

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With the successful development of unconventional hydrocarbons, the production of unconventional hydrocarbons has increased rapidly. However, a single conventional or unconventional model is not suitable for the mechanism of hydrocarbon accumulation in a given basin or sag. Based on data from drilling, logging, and geophysical analysis, the hydrocarbon accumulation mechanism in the Hari sag in the Yingen-Ejinaqi basin, China, was analyzed. There are three sets of source rocks in the Hari sag: the K1y source rocks were evaluated as having excellent source rock potential with low thermal maturity and kerogen Type I-II1; the K1b2 source rocks were evaluated as having good source rock potential with mature to highly mature stages and kerogen Type II1-II2; and the K1b1 source rocks were evaluated as having moderate source rock potential with mature to highly mature stages and kerogen Type II1-II2. Reservoir types were found to be conventional sand reservoirs, unconventional carbonate-shale reservoirs, and volcanic rock reservoirs. There were two sets of fault-lithologic traps in the Hari sag, which conform to the intra-source continuous hydrocarbon accumulation model and the approaching-source discontinuous hydrocarbon accumulation model. The conclusions of this research provide guidance for exploring multi-type reservoirs and multi-type hydrocarbon accumulation models.
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Guram N., Gordadze, Giruts Maxim V., Poshibaeva Aleksandra R., Postnikova Olga V., Poshibaev Vladimir V., Antipova Olga A., Rudakovskaya Svetlana Yu., Koshelev Vladimir N., and Martynov Viktor G. "Carbonate Reservoir as a Source Rock." Journal of Siberian Federal University. Chemistry 11, no. 4 (December 2018): 575–92. http://dx.doi.org/10.17516/1998-2836-0101.

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Ma, Feng, Wei Yang, Yongshu Zhang, Hongzhe Li, Mei Xie, Xiujian Sun, Pu Wang, and Yadong Bai. "Characterization of the reservoir-caprock of the large basement reservoir in the Dongping field, Qaidam Basin, China." Energy Exploration & Exploitation 36, no. 6 (April 26, 2018): 1498–518. http://dx.doi.org/10.1177/0144598718772317.

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The basement gas reservoir in the Dongping field in the Qaidam Basin is a large reservoir that is different from other basement reservoirs around the world. The basement reservoir does not contain thick mudstone with abundant organic matter that acts as both a source rock and a caprock. The natural gas came from lateral Jurassic source rocks. The basement lithologies in wellblocks Dp3, Dp1, and Dp17 are granite, granitic gneiss, and limestone with slate, respectively, but they all provide effective reservoir space for gas accumulation. The average porosities are 3.3%, 5.2%, and 3.6%, respectively, and the average permeabilities are 0.66 mD, 0.60 mD, and 0.57 mD, respectively. Tectonic fractures are the main factor for improving the physical properties of the reservoir, and secondary solution space is the key factor for the high and stable gas production in the study area. The E1 + 2 Formation, which contains abundant anhydrite, unconformably overlies the basement rock. Some of the anhydrite was deposited as cement and filled the fractures and pores, which led to decreased porosity and to the formation of a tight caprock with a high breaking pressure for hydrocarbon accumulation. The caprock becomes thinner from the lowland to the uplift, and it is missing in wellblock Dp3, which led to the heterogeneous distribution of gas. Anhydrite-bearing caprock is the dominant factor that controls the gas accumulation in the basement rock reservoir in the Dongping field. Studying the spatial distribution of the anhydrite-bearing caprock is important to the exploration and development of basement gas reservoirs in the Qaidam Basin. This unique gas accumulation mechanism in a basement rock reservoir may inspire new ideas for exploring basement oil and gas reservoirs around the world.
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Bian, Baoli, Ablimit Iming, Tianze Gao, Hailei Liu, Wenlong Jiang, Xueyong Wang, and Xiujian Ding. "Petroleum Geology and Exploration of Deep-Seated Volcanic Condensate Gas Reservoir around the Penyijingxi Sag in the Junggar Basin." Processes 10, no. 11 (November 17, 2022): 2430. http://dx.doi.org/10.3390/pr10112430.

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Many types of volcanic rock oil and gas reservoirs have been found in China, showing great petroleum exploration potential. Volcanic reservoir also is one of the key fields of exploration in the Junggar Basin and mainly concentrated in the middle and shallow layers, while the deep volcanic rock and natural gas fields have not been broken through. Based on comprehensive analysis of core observation, single well analysis, reservoir description, source rocks evaluation, combined with seismic data and time-frequency electromagnetic technology, multiple volcanic rock exploration targets were identified, and industrial oil and gas flow was obtained in the well SX 16 of the Penyijingxi Sag, western Junggar Basin. It is believed that the deep Permian source rocks have relatively higher natural gas generation potential and volcanic breccia usually have large reservoir space. And the mudstone of the Upper Wuerhe Formation played as the role of caprock. The success of exploration well SX16 has achieved a major breakthrough in natural gas exploration in the Penyijingxi Sag, which has essential guiding significance for the exploration of deep volcanic rocks and large-scale gas exploration in the Junggar Basin.
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Guo, Qiang, Da Kang Zhong, Yu Lin Wang, and Yan Chun Zhong. "Characteristics of Petroleum Geology and Prediction of Favorable Areas in Jiufotang Formation, Kazuo Basin." Advanced Materials Research 361-363 (October 2011): 3–7. http://dx.doi.org/10.4028/www.scientific.net/amr.361-363.3.

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Through the research on actual measurement 106km geological profile, the hydrocarbon source rocks mainly develop the third member of Jiufotang formation, followed by the second member. There are five distribution areas where have been divided hydrocarbon source rocks thickness is more than 400m in study area. Among them, Jiufotang area has the greatest sedimentary thickness of hydrocarbon source rocks, while Siguanyingzi-Sanjiazi area has the largest area where hydrocarbon source rocks are more than 400m. Oil shale is good hydrocarbon source rock, while dark gray and black gray mudstone (or shale) are relatively poor. The fan delta front subaqueous distributary channel and mouth bar are well-developed in basin’s fault zone and also the important favorable reservoir, followed by braided delta front mouth bar, subaqueous distributary channel and distal bar developing in northwestern area of the basin. There are four forms of source-reservoir-cap combination: (1) hydrocarbon source rock in the above layer and reservoir in the below layer; (2) hydrocarbon source rock and reservoir in the same layer; (3) normal form; (4) fingerlike intersection. The combination of fingerlike intersection is the most important forms in study area. Fan delta facies next to lacustrine facies is favorable exploration area.
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Li, Xiaoshan, Hong Pan, Yuxiao Wu, Guanxing Luo, Junqiang Song, Liu Yang, Kaifang Gu, et al. "Main Control Factors and Hydrocarbon Accumulation Model of Volcanic Oil Reservoirs with Complex Oil–Water Relationships: A Case Study of the Carboniferous in the Chepaizi Uplift, the Junggar Basin, China." Minerals 12, no. 11 (October 26, 2022): 1357. http://dx.doi.org/10.3390/min12111357.

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In order to study the main control factors of volcanic reservoirs with complex oil–water relationships, the Carboniferous in the Chepaizi Uplift of the Junggar Basin was taken as an example and the lithofacies characteristics, main control factors, and hydrocarbon accumulation model of volcanic reservoirs were investigated by combining the petroleum geology with field testing (data of core analysis, well logging, formation testing, and production testing). The results show that the Carboniferous in the Chepaizi Uplift experienced three stages of volcanic activities and developed seven volcanic lithofacies bodies, distributed in a bead-string connected planar form along the Hongche fault. There is no unified oil–water interface across the whole study area and there are multiple oil–water systems within one fault block. The Carboniferous volcanic reservoir experienced two stages of hydrocarbon accumulation from two different source rocks. The distribution of faults penetrating hydrocarbon kitchens and source rocks controls the macro-scale distribution of reservoirs. The physical properties of reservoirs affect the pattern of oil and water differentiation in volcanic rock bodies, while the lithofacies body-controlled hydrocarbon accumulation mode highlighting “one rock body for one reservoir” determines the distribution of reservoirs. The matching between the paleo-structure and hydrocarbon accumulation stage controls the accumulation and adjustment of hydrocarbon distribution. The Permian source rocks in the Shawan Sag serve as the lateral hydrocarbon supply and hydrocarbons accumulate in the Carboniferous structural-lithologic traps, which are summarized as the two stages of hydrocarbon accumulation of newly generated hydrocarbons into older reservoir rocks. This study of the hydrocarbon accumulation pattern in volcanic rocks aims at guiding the development of Carboniferous reservoirs with complex oil and water relationships in this area.
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WANG, WEIMING, ZHIXUAN WANG, XUAN CHEN, FEI LONG, SHUANGFANG LU, GUOHONG LIU, WEICHAO TIAN, and YUE SU. "FRACTAL NATURE OF POROSITY IN VOLCANIC TIGHT RESERVOIRS OF THE SANTANGHU BASIN AND ITS RELATIONSHIP TO PORE FORMATION PROCESSES." Fractals 26, no. 02 (April 2018): 1840007. http://dx.doi.org/10.1142/s0218348x18400078.

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In this paper, in a case study of Santanghu Basin in China, the morphological characteristics and size distribution of nanoscale pores in the volcanic rocks of the Haerjiawu Formation were investigated using the results of low temperature nitrogen adsorption experiments. This research showed that within the target layer, a large number of nanoscale, eroded pores showed an “ink bottle” morphology with narrow pore mouths and wide bodies. The fractal dimension of pores increases gradually with increasing depth. Moreover, as fractal dimension increases, BET-specific surface area gradually increases, average pore diameter decreases and total pore volume gradually increases. The deeper burial of the Haerjiawu volcanic rocks in the Santanghu Basin leads to more intense erosion by organic acids derived from the basin’s source rocks. Furthermore, the internal surface roughness of these corrosion pores results in poor connectivity. As stated above, the corrosion process is directly related to the organic acids generated by the source rock of the interbedded volcanic rocks. The deeper the reservoir, the more the organic acids being released from the source rock. However, due to the fact that the Haerjiawu volcanic rocks are tight reservoirs and have complicated pore-throat systems, while organic acids dissolve unstable minerals such as feldspars which improve the effective reservoir space; the dissolution of feldspars results in the formation of new minerals, which cannot be expelled from the tight reservoirs. They are instead precipitated in the fine pore throats, thereby reducing pore connectivity, while enhancing reservoir micro-preservation conditions.
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Dissertations / Theses on the topic "Source rock reservoir"

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Börner, Jana H. "Electrical phenomena during CO2–rock interaction under reservoir conditions : experimental investigations and their implications for electromagnetic monitoring applications." Doctoral thesis, Technische Universitaet Bergakademie Freiberg Universitaetsbibliothek "Georgius Agricola", 2016. http://nbn-resolving.de/urn:nbn:de:bsz:105-qucosa-206674.

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Geophysical methods are essential for exploration and monitoring of subsurface formations, e.g. in carbon dioxide sequestration or enhanced geothermal energy. One of the keys to their successful application is the knowledge of how the measured physical quantities are related to the desired reservoir parameters. The work presented in this thesis shows that the presence of carbon dioxide (CO2) in pore space gives rise to multiple processes all of which contribute to the electrical rock conductivity variation. Basically, three mechanisms take place: (1) CO2 partially replaces the pore water, which is equivalent to a decrease in water saturation. (2) CO2 chemically interacts with the pore water by dissolution and dissociation. These processes change both the chemical composition and the pH of the pore filling fluid. (3) The low-pH environment can give rise to mineral dissolution and/or precipitation processes and changes the properties of the grain-water interface. Investigations on the pore water phase show that the reactive nature of CO2 in all physical states significantly acts on the electrical conductivity of saline pore waters. The physico-chemical interaction appears in different manifestations depending mainly on the pore water composition (salinity, ion types) but also on both temperature and pressure. The complex behaviour includes a low- and a high-salinity regime originating from the conductivity increasing effect of CO2 dissociation, which is opposed by the conductivity decreasing effect of reduced ion activity caused by the enhanced mutual impediment of all solutes. These results are fundamental since the properties of the water phase significantly act on all conduction mechanisms in porous media. In order to predict the variation of pore water conductivity, both a semi-analytical formulation and an empirical relationship for correcting the pore water conductivity, which depends on salinity, pressure and temperature, are derived. The central part of the laboratory experiments covers the spectral complex conductivity of water-bearing sand during exposure to and flow-through by CO2 at pressures up to 30MPa and temperatures up to 80°C. It is shown that the impact of CO2 on the real part of conductivity of a clean quartz sand is dominated by the low- and high-salinity regime of the pore water. The obtained data further show that chemical interaction causes a reduction of interface conductivity, which could be related to the low pH in the acidic environment. This effect is described by a correction term, which is a constant value as a first approximation. When the impact of CO2 is taken into account, a correct reconstruction of fluid saturation from electrical measurements is possible. In addition, changes of the inner surface area, which are related to mineral dissolution or precipitation processes, can be quantified. Both the knowledge gained from the laboratory experiments and a new workflow for the description and incorporation of geological geometry models enable realistic finite element simulations. Those were conducted for three different electromagnetic methods applied in the geological scenario of a fictitious carbon dioxide sequestration site. The results show that electromagnetic methods can play an important role in monitoring CO2 sequestration. Compared to other geophysical methods, electromagnetic techniques are generally very sensitive to pore fluids. The proper configuration of sources and receivers for a suitable electromagnetic method that generates the appropriate current systems is essential. Its reactive nature causes CO2 to interact with a water-bearing porous rock in a much more complex manner than non-reactive gases. Without knowledge of the specific interactions between CO2 and rock, a determination of saturation and, consequently, a successful monitoring are possible only to a limited extend. The presented work provides fundamental laboratory investigations for the understanding of the electrical properties of rocks when the reactive gas CO2 enters the rock-water system. All laboratory results are put in the context of potential monitoring applications. The transfer from petrophysical investigations to the planning of an operational monitoring design by means of close-to-reality 3D FE simulations is accomplished.
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Abdulla, Fawzeiah Hussien Ali. "Source rock evaluation and maturity studies of Lower and Middle Cretaceous formations in Kuwait." Thesis, Imperial College London, 1993. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.312472.

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Nabiyev, Anar. "Edimentology And Stratigraphy Of Turbeyani Marl Sequences And Inpiri Limestones (late Barremian - Albian): Implications For Possible Source And Reservoir Rocks (nw Turkey)." Master's thesis, METU, 2007. http://etd.lib.metu.edu.tr/upload/12608516/index.pdf.

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SEDIMENTOLOGY AND STRATIGRAPHY OF TÜ
RBEYANI MARL SEQUENCES AND iNPiRi LIMESTONES (LATE BARREMIAN - ALBIAN): IMPLICATIONS FOR POSSIBLE SOURCE AND RESERVOIR ROCKS (NW TURKEY) Anar Nabiyev M.Sc., Department of Geological Engineering Supervisor: Assist. Prof. Dr. i. Ö
mer Yilmaz April 2007, 105 pages Sedimentology, cyclostratigraphy and sequence stratigraphy of the Tü
rbeyani Marls (Albian) and the inpiri Limestone (Upper Barremian-Albian) members of Ulus Formation (incigez, Bartin, Amasra) were interpreted in this study. In the Tü
rbeyani Marls total of five different facies were defined. Marl and limestone facies are the most abundant in the succession. The depositional environment of the succession was defined as an outer shelf area. Within the pelagic marls 39 smaller order and 9 higher order cycles were recognized. These cycles correspond to the parasequences and parasequence sets of sequence stratigraphy, respectively. In the measured section only one type-3 sequence boundary was identified. In the inpiri Limestones great variety of limestone facies are represented. Bioclastic, peloidal, intraclastic wackestone-packstone-grainstone facies are the most abundant. Moreover, occurrence of lime mudstone, fenestral limestone, ooid packstone-grainstone, and sandstone facies are present as well. In the measured section of the inpiri Limestones 25 fifth order and 6 fourth order cycles were defined. These cycles correspond to the parasequence sets and systems tracts of the sequence stratigraphy, respectively. Total of three transgressive and three highstand systems tract were defined. Only one type 2 sequence boundary was identified in the measured section, the rest of them are interrupted by covers. This study revealed that the Tü
rbeyani Marls and the inpiri Limestones are not economically valuable as petroleum source and reservoir rocks, respectively. The total organic carbon (TOC) values of marl facies of the Tü
rbeyani marls are very low, and the pore spaces observed in the inpiri Limestone are cement filled making it unsuitable reservoir rock. Keywords: sedimentology, cyclostratigraphy, sequence stratigraphy, Tü
rbeyani Marls, inpiri Limestones, Albian, Upper Barremian, Amasra, Bartin.
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Baldwin, Patrick W. "LITHOSTRATIGRAPHIC AND GEOCHEMICAL CHARACTERIZATION OF THE UPPER PENNSYLVANIAN ‘WOLFCAMP D’ SHALE, MIDLAND BASIN (USA): IMPLICATIONS FOR PALEOENVIRONMENTS AND UNCONVENTIONAL PETROLEUM RESERVIORS." UKnowledge, 2016. http://uknowledge.uky.edu/ees_etds/35.

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An integrated stratigraphic analysis of a ~350 ft drill core from Upton County (Texas) has revealed pervasive variability of several key siliciclastic and carbonate lithofacies in vertical section, where organic-rich siliceous mudrock beds alternate with aluminum-rich mudrocks and calcareous gravity flow deposits. Sediment chemistry, especially major and trace elements derived from x-ray fluorescence, captures this variability with high sensitivity. The high frequency chemostratigraphic variability appears to be cyclic, and it is interpreted to represent the first example of deep-water Late Pennsylvanian cyclothems for the Midland Basin. Positive trace metal (Mo, Cr) correlations to total organic carbon and gamma ray response in siliceous mudrocks, in conjunction with abundant pyrite, indicate bottom-water anoxia and possibly euxinia within the basin. The influence of glacial ice-sheets on the water level of the global ocean, in concert with local oceanographic gradients, regional tectonics, and tropical paleoclimate, constitute the primary controls on lithofacies and chemostratigraphy. The results of this study have implications for understanding the depositional history of the Midland Basin, as well as for identifying horizontal drilling zones for resource development.
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Mohammed, R. Luma Jassim [Verfasser], Lorenz [Akademischer Betreuer] Schwark, and Wolfgang [Gutachter] Kuhnt. "Petroleum system analysis of the Lower Jurassic-Upper Cretaceous source rocks and Miocene reservoirs in the NE of Iraq / Luma Jassim Mohammed R ; Gutachter: Wolfgang Kuhnt ; Betreuer: Lorenz Schwark." Kiel : Universitätsbibliothek Kiel, 2016. http://d-nb.info/1236286944/34.

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Quick, Russell Emerson Edward. "Petroleum geochemistry of a source rock-reservoir contact /." 1991. http://collections.mun.ca/u?/theses,126100.

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Lehne, Eric [Verfasser]. "Geochemical study on reservoir and source rock asphaltenes and their significance for hydrocarbon generation / vorgelegt von Eric Lehne." 2007. http://d-nb.info/987575899/34.

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Dunlop, Erik Christopher. "Controls on Gas Production from Permian Ultra-deep Coal Seams of the Cooper Basin: Expanding Reservoir Boundary Theory." Thesis, 2019. http://hdl.handle.net/2440/123421.

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This thesis reveals atypical dynamic reservoir behaviour within Cooper Basin ultra-deep coal seams during gas production that calls for a paradigm shift in gas extraction technology, diametrically opposed to the evolutionary path of current drilling, wellbore completion, and reservoir stimulation practices. An anomalous geomechanical reservoir boundary condition is detected that is, by definition, mostly restricted to ultra-deep coal seams. The discovery has resulted in the formulation of a new coal seam reservoir concept - “Expanding Reservoir Boundary Theory”. Ultra-deep Permian coal seams of the Cooper Basin in central Australia represent a nascent thermogenic source rock reservoir play. Proof-of-concept gas flow occurred in 2007. The vast (100+ Tscf) potential resource is comparable in commercial significance, and technical challenge, to the shale gas plays of North America. As with shale, full-cycle, standalone commercial gas production from Cooper Basin ultra-deep coal seams requires a large, complex, permeable “stimulated reservoir volume” (SRV) domain having high fracture / fabric face surface area for gas desorption. This goal has not yet been achieved after 13 years of trials because, owing to the bipolar combination of coal-like geomechanical properties and shale-like reservoir properties, these poorly cleated, inertinitic coal seams exhibit “hybrid” characteristics. This is problematic for achieving effective reservoir stimulation, and poses the greatest immediate challenge. Stimulation techniques adopted from other play types are incompatible with the highly unfavourable combination of nanoDarcy-scale permeability, “ductility”, and high stress. The Cooper Basin Deep Coal Gas (CBDCG) Play commences 6,000 feet (1,830 metres) below the “commercial permeability depth limit” for most shallow coal seam gas (CSG) reservoirs but this does not reduce gas flow potential. Shale gas industry technologies have, in principle, eliminated the requirement for naturally occurring coal fabric permeability. Optimum reservoir conditions occur at depths beyond 9,000 feet (2,740 metres), driven by very low water saturation, high gas content, gas oversaturation, overpressure, rigid host rock strata, and high deviatoric stress. The limited literature does not yet adequately characterise the physical response of ultra-deep coal seams, and the surrounding host rock strata, to production pressure drawdown. It remains to be established how artificial fracture and coal fabric aperture width change as a consequence of the dynamic, diametric competition between gas desorption-induced coal matrix shrinkage and the omnipresent tendency for reservoir compaction caused by increasing production pressure drawdown-induced effective stress. This technical impasse, inhibiting commercialisation, is addressed by analysing the atypical flowback behaviour of hydraulically fracture stimulated coal seams within a dedicated vertical wellbore at 9,500 feet (2,900 metres). High-resolution, non-classical flowback analysis is performed on the pure dataset of Australia’s first ultra-deep coal gas well. Wellhead and fracture network pressures are recorded continuously for 8 1/2 years, at a 10-minute sample interval, while flowing to atmosphere. Natural flowback behaviour is analogous to that of a mechanical gas plunger artificial lift system. A low but gradually increasing quasi-steady state base gas flow, free of produced formation water, is overprinted by a non-steady state, cyclical pressure signature that is diagnostic of dynamic reservoir behaviour during gas production. A total of 114 high-rate, “geyser-like” gas surge events, gradually increasing in duration from 2 hours to 2 weeks, and in reservoir equivalent volume from 360 to 20,000 rcf (10 to 570 rcm), suggest the gas headspace compartment of a “down-hole void space domain” is steadily increasing in size. The gas surge events result from intermittent release of fracture network gas, hydrostatically compressed by flowback fluid slowly accumulating within the wellbore. A production “history match” for the gas surge event pressure profile is obtained by designing, fabricating, operating, and data logging a computer-controlled hydraulic apparatus within The University of Adelaide’s experimental wellbore, at a depth of 230 feet (70 metres). This physically simulates open-ended flowing manometer-like hydrodynamic behaviour of the wellbore-reservoir system. A postulated geological trigger mechanism for surge initiation is tested and validated; “wellbore hydrostatic back-pressure and reservoir stress-dependent leak-off”. Time-lapse pressure transient analysis (PTA) is performed on three extended wellbore pressure build-up tests, lasting 157, 259, and 295 days respectively. Increasing permeability is recognised within coal fabric surrounding the initial fracture network SRV domain. Time-lapse rate transient analysis (RTA) performed on the first two subsequent wellbore pressure “blow-down to atmosphere” (BDTA) gas flow rate decline profiles indicates that hydraulic fracture flow conductivity increased during the intervening 327-day flowback period. Interpreted dilation of hydraulic fracture apertures is supported by a 60% increase in the initial BDTA gas flow rates, from 7.5 to 12.0 MMscfd (212.4 to 340.0 Mscmd). Cooper Basin ultra-deep coal gas reservoirs behave differently to other deep, thermogenic source rock reservoirs, and require a paradigm shift in reservoir stimulation technology that does not rely exclusively upon hydraulic fracture stimulation and the “brittleness factor”. Pressure arching may fill this role by neutralising the omnipresent tendency for reservoir compaction caused by increasing production pressure drawdown-induced effective stress. The combined, mutually sustaining actions of desorption-induced coal matrix shrinkage and sympathetic pressure arch “stress shield” evolution generate an “expanding reservoir boundary and decreasing confining stress” condition that allows producing ultra-deep coal seams, and adjacent strata indirectly (which may include other reservoir types), to progressively de-stress and “self-fracture” in an overall state of endogenous tensile failure. As with underground coal mine excavations, pressure arching will deflect maximum stress vectors around the dilating “dispersed coal fabric void space” domain of a growing fracture network SRV domain that has developed reduced bulk structural integrity, and reduced bulk compressive strength, compared to the surrounding native coal seam and host rock strata. Size and effectiveness of pressure arching increases with depth. Cooper Basin ultra-deep coal seams, and adjacent “non-coal” reservoirs indirectly, may be effectively stimulated to flow gas on a large scale by harnessing this self-perpetuating, depth-resistant mechanism for creating coal fracture / fabric permeability and surface area for gas desorption. They may be induced to pervasively “shatter”, or “self-fracture”, naturally during gas production, independent of the lack of “brittleness”, analogous to the manner in which shrinkage crack networks slowly form, in a state of intrinsic, endogenous tension, within desiccating clay-rich surface sediment. Full-cycle, standalone commercial gas production is considered likely to occur when “Expanding Reservoir Boundary Theory” is applied, so as to replicate the very large, complex fracture network SRV domain of commercial shale gas reservoirs.
Thesis (Ph.D.) -- University of Adelaide, Australian School of Petroleum, 2020
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Books on the topic "Source rock reservoir"

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Hazra, Bodhisatwa, David A. Wood, Devleena Mani, Pradeep K. Singh, and Ashok K. Singh. Evaluation of Shale Source Rocks and Reservoirs. Cham: Springer International Publishing, 2019. http://dx.doi.org/10.1007/978-3-030-13042-8.

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Singh, Ashok K., Bodhisatwa Hazra, Devleena Mani, Pradeep K. Singh, and Wood David A. Evaluation of Shale Source Rocks and Reservoirs. Springer, 2020.

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Singh, Ashok K., Bodhisatwa Hazra, Devleena Mani, Pradeep K. Singh, and Wood David A. Evaluation of Shale Source Rocks and Reservoirs. Springer, 2019.

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(Editor), P. M. Harris, and L. J. Weber (Editor), eds. Giant Hydrocarbon Reservoirs of the World: From Rocks to Reservoir Characterization and Modeling (Aapg Memoir). Amer Assn of Petroleum Geologists, 2006.

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Camp, Wayne K., Neil S. Fishman, Paul C. Hackley, Joe H. S. Macquaker, Kitty L. Milliken, and Kevin G. Taylor, eds. Memoir 120: Mudstone Diagenesis: Research Perspectives for Shale Hydrocarbon Reservoirs, Seals, and Source Rocks. AAPG, 2019. http://dx.doi.org/10.1306/aapg120.

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Book chapters on the topic "Source rock reservoir"

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Ganz, Sh N., W. Kalkreuth, F. öner, M. J. Pearson, and H. Wehner. "Characterization of Source Rock and Reservoir Qualities Using Infrared Analysis." In The European Oil and Gas Conference, 207. Dordrecht: Springer Netherlands, 1991. http://dx.doi.org/10.1007/978-94-010-9844-1_27.

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Stein, Rüdiger. "Source Rocks, Reservoirs." In Encyclopedia of Marine Geosciences, 1–2. Dordrecht: Springer Netherlands, 2014. http://dx.doi.org/10.1007/978-94-007-6644-0_151-3.

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Stein, Rüdiger. "Source Rocks, Reservoirs." In Encyclopedia of Marine Geosciences, 792–93. Dordrecht: Springer Netherlands, 2016. http://dx.doi.org/10.1007/978-94-007-6238-1_151.

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Hazra, Bodhisatwa, David A. Wood, Devleena Mani, Pradeep K. Singh, and Ashok K. Singh. "Source-Rock Evaluation Using the Rock-Eval Technique." In Evaluation of Shale Source Rocks and Reservoirs, 19–49. Cham: Springer International Publishing, 2019. http://dx.doi.org/10.1007/978-3-030-13042-8_3.

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Naqi, Mohammad, Ohood Alsalem, Suad Qabazard, and Fowzia Abdullah. "Petroleum Geology of Kuwait." In The Geology of Kuwait, 117–44. Cham: Springer International Publishing, 2022. http://dx.doi.org/10.1007/978-3-031-16727-0_6.

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AbstractKuwait has proven conventional oil reserves of about 100 billion barrels which makes it one of the major oil-producing countries worldwide. Most of this reserve is found in Cretaceous and Jurassic with minor quantities in the Paleogene sedimentary successions. Most hydrocarbon production comes from the siliciclastic Burgan Formation which is the most important reservoir in Kuwait. The Jurassic and Lower Cretaceous exhibit good quality source rocks that charged most of the hydrocarbon reservoirs in Kuwait and entered the oil window in Late Cretaceous to Eocene. Most of the hydrocarbon is trapped in very gentle four-way closure structures that are related to the deep-seated fault system of the Arabian Peninsula such as Khurais-Burgan Anticline. Hydrocarbon reservoirs in Kuwait are sealed and capped mainly by shale rocks and to a less extent by evaporites. In the last 15 years, Kuwait Oil Company (KOC) displayed interest in commercially exploiting unconventional hydrocarbon reserves and started laying significant emphasis on the exploration and development of unconventional resources. The aim of this work is to summarize the different petroleum systems of Kuwait including the Paleozoic, Mesozoic, and Cenozoic systems.
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Hazra, Bodhisatwa, David A. Wood, Devleena Mani, Pradeep K. Singh, and Ashok K. Singh. "Source-Rock Geochemistry: Organic Content, Type, and Maturity." In Evaluation of Shale Source Rocks and Reservoirs, 7–17. Cham: Springer International Publishing, 2019. http://dx.doi.org/10.1007/978-3-030-13042-8_2.

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Hazra, Bodhisatwa, David A. Wood, Devleena Mani, Pradeep K. Singh, and Ashok K. Singh. "Introduction." In Evaluation of Shale Source Rocks and Reservoirs, 1–6. Cham: Springer International Publishing, 2019. http://dx.doi.org/10.1007/978-3-030-13042-8_1.

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Hazra, Bodhisatwa, David A. Wood, Devleena Mani, Pradeep K. Singh, and Ashok K. Singh. "Matrix Retention of Hydrocarbons." In Evaluation of Shale Source Rocks and Reservoirs, 51–56. Cham: Springer International Publishing, 2019. http://dx.doi.org/10.1007/978-3-030-13042-8_4.

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Hazra, Bodhisatwa, David A. Wood, Devleena Mani, Pradeep K. Singh, and Ashok K. Singh. "Kerogen’s Potential to Be Converted into Petroleum: Reaction Kinetics and Modelling Thermal Maturity Plus Petroleum Transformation Processes." In Evaluation of Shale Source Rocks and Reservoirs, 57–84. Cham: Springer International Publishing, 2019. http://dx.doi.org/10.1007/978-3-030-13042-8_5.

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Hazra, Bodhisatwa, David A. Wood, Devleena Mani, Pradeep K. Singh, and Ashok K. Singh. "Sedimentary Biomarkers and Their Stable Isotope Proxies in Evaluation of Shale Source and Reservoir Rocks." In Evaluation of Shale Source Rocks and Reservoirs, 85–106. Cham: Springer International Publishing, 2019. http://dx.doi.org/10.1007/978-3-030-13042-8_6.

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Conference papers on the topic "Source rock reservoir"

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Chen, Jin-Hong, Stacey Althaus, and Mohammed Boudjatit. "Optimization of NMR Permeability Transform and Application to a Source Rock Reservoir." In International Petroleum Technology Conference. IPTC, 2022. http://dx.doi.org/10.2523/iptc-22195-ea.

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Abstract Permeability is a fundamentally important property of reservoir rocks that governs the flow of the reservoir fluids and production rates. Many methods have been developed to estimate permeability, including well established and documented laboratory measurements on whole core and plugs, analysis of formation test data, and analysis of production. Obtaining permeability from nuclear magnetic resonance (NMR) T1 or T2 has proven to be a cost effective method that can provide continuous permeability along a wellbore. This method uses a transform function on NMR well log data to calculate permeability. An accurate NMR permeability transform requires calibration to fit local data of a specific field based on measured data from representative cores from the field. The general form of the permeability transform developed for conventional sandstone and carbonate reservoirs does not work well for extremely tight reservoirs such as source rocks. Here we show a generic optimization method to find the optimal permeability transform for any tight reservoirs using NMR log data and laboratory measured permeability data from samples at selected depth of the logged well. This optimization method is applied to a source rock well and a permeability transform was obtained. The transform is a function of the movable fluid in the rock and logarithm mean of the NMR relaxation time. The permeability calculated from the transform is comparable to measured permeability from core samples.
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Baig, Muhammad Zeeshan, Pierre Van Laer, Karl Leyrer, Gennady Makrachev, Hassan Al Marzooqi, Salama Al Suwaidi, Ishan Raina, and Suvodip Dasgupta. "Assessing Reservoir Quality of the Diyab Source Rock in UAE." In Abu Dhabi International Petroleum Exhibition & Conference. Society of Petroleum Engineers, 2017. http://dx.doi.org/10.2118/188433-ms.

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Shelley, Robert, Amir Mohammad Nejad, and Stanislav Sheludko. "Source Rock Reservoir Characterization Using Geology, Geochemical and Drilling Data." In Unconventional Resources Technology Conference. Tulsa, OK, USA: American Association of Petroleum Geologists, 2017. http://dx.doi.org/10.15530/urtec-2017-2667653.

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Baruah, S., and H. G. Pham. "Petrophysical Estimation Of Toc For Assessment Of Hc Potential Of The Source Rock Shales, Assam Basin, India." In EAGE Conference on Reservoir Geoscience. European Association of Geoscientists & Engineers, 2018. http://dx.doi.org/10.3997/2214-4609.201803293.

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Mesdour, Rabah, Moemen Abdelrahman, and Abdulbari Alhayaf. "Workflow to Optimize Cluster Spacing Design of Horizontal Multistage Fractured Well in Unconventional Source Rock." In SPE Middle East Oil & Gas Show and Conference. SPE, 2021. http://dx.doi.org/10.2118/204891-ms.

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Abstract Horizontal drilling and multistage hydraulic fracturing applied in unconventional reservoirs over the past decade to create a large fracture surface area to improve the well productivity. The combination of reservoir quality with perforation cluster spacing and fracture staging are keys to successful hydraulic fracturing treatment for horizontal wells. The objective of this work is to build and calibrate a dynamic model by integrating geologic, hydraulic fracture, and reservoir modeling to optimize the number of clusters and other completion parameters for a horizontal well drilled in the source rock reservoir using simulation and analytical models. The methodology adopted in this study covers the integration of geological, petrophysical, and production data analysis to evaluate reservoir and completion qualities and quantify the heterogeneity and the perforation clusters number required within a frac stage. Assuming all perforation clusters are uniformly distributed within a stage. The hydraulic planer fracture attributes assumed and the surface production measurement together with the production profile were used to calibrate the reservoir model. The properties of the Stimulated Reservoir Volume "SRV" were defined after the final calibration using reservoir model including hydraulic fractures. The calibrated reservoir model was used to carry out sensitivity analyses for cluster spacing optimization and other completion parameters considering the surface and reservoir constraints. An optimum cluster spacing was observed based on the Estimated Ultimate Recovery "EUR" of the subject well by reservoir properties. The final results based on 70% of perforation clusters contribution to production observed from PLT log, and the results of this study were implemented. Afterwards, another study has been undertaken to increasing the stimulation effectiveness and maximizing the number of perforation clusters contributing to productivity as an area for improvement to engineering the completion design. The methodology adopted in this study identifies the most important parameters of completion affecting well productivity for specific unconventional reservoirs. This study will help to engineer completion design, improve cluster efficiency, reduce cost and increase well EUR for the development phase.
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Salufu, Samuel, Rita Onolemhemhen, and Sunday Isehunwa. "Hydrocarbon Generation Indication from Source Rock to Reservoir Rock: Case Studies of Anambra and Abakaliki Basins South-Eastern Nigeria." In SPE/AAPG Africa Energy and Technology Conference. SPE, 2016. http://dx.doi.org/10.2118/afrc-2560967-ms.

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ABSTRACT This paper sought to use information from outcrop sections to characterize the source and reservoir rocks in a basin in order to give indication(s) for hydrocarbon generation potential in a basin in minimizing uncertainty and risk that are allied with exploration and field development of oil and gas, using subsurface data from well logs, well sections, seismic and core. The methods of study includes detailed geological, stratigraphical, geochemical, structural,, petro-graphical, and sedimentological studies of rock units from outcrop sections within two basins; Anambra Basin and Abakaliki Basin were used as case studies. Thirty eight samples of shale were collected from these Basins; geochemical analysis (rockeval) was performed on the samples to determine the total organic content (TOC) and to assess the oil generating window. The results were analyzed using Rock wares, Origin, and Surfer software in order to properly characterize the potential source rock(s) and reservoir rock(s) in the basins, and factor(s) that can favour hydrocarbon traps. The results of the geological, stratigraphical, sedimentological, geochemical, and structural, were used to developed a new model for hydrocarbon generation in the Basins. The result of the geochemical analysis of shale samples from the Anambra Basin shows that the TOC values are ≥ 1wt%, Tmax ≥ 431°C, Vitrinite reflectance values are ≥ 0.6%, and S1+S2 values are > 2.5mg/g for Mamu Formation while shale samples from other formations within Anambra Basin fall out of these ranges. The shale unit in the Mamu Formation is the major source rock for oil generation in the Anambra Basin while others have potential for gas generation with very little oil generation. The shale samples from Abakaliki Basin shows that S1+S2 values range from< 1 – 20mg/g, TOC values range from 0.31-4.55wt%, vitrinite reflectance ranges from 0.41-1.24% and Tmax ranges from423°C – 466°C. This result also shows that there is no source rock for oil generation in Abakaliki Basin; it is either gas or graphite. This observation indicates that all the source rocks within Abakaliki Basin have exceeded petroleum generating stage due to high geothermal heat resulting from deep depth or the shale units have not attained catagenesis stage as a result of S1+S2 values lesser than 2.5mg/g despite TOC values of ≥ 0.5wt% and vitrinite reflectance values of ≥ 0.6%. The novelty of this study is that the study has been able to show that here there is much more oil than the previous authors claimed, and the distribution of this oil and gas in the basins is controlled by two major factors; the pattern of distribution of the materials of the source rock prior to subsidence and during the subsidence period in the basin, and the pattern and the rate of tectonic activities, and heat flow in the basin. If these factors are known, it would help to reduce the uncertainties associated with exploration for oil and gas in the two basins.
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Biteau, J. "Reservoir, Seal, Source Rock, a Continuity in the Petroleum System Components." In 81st EAGE Conference and Exhibition 2019. European Association of Geoscientists & Engineers, 2019. http://dx.doi.org/10.3997/2214-4609.201901592.

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Guo, Wang, Gang Chen, and Yuhong Li. "Oil-Source Rock Correlation of Reservoir Bitumen in Deeply Buried Reservoir of Ordos Basin, China." In Goldschmidt2020. Geochemical Society, 2020. http://dx.doi.org/10.46427/gold2020.906.

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Ding, Qian, Zhiliang He, Dongya Zhu, and Jingbin Wang. "Simulation Experiments of Carbonate Reservoir Modification by Source Rock-Derived Acidic Fluids." In Goldschmidt2020. Geochemical Society, 2020. http://dx.doi.org/10.46427/gold2020.584.

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Al-Enezi, Huda Rajab, and Iraj Ershaghi. "Ineffectiveness of Acid Fracturing for Stimulating a Tight Fractured Reservoir Rock, A Case Study." In SPE Western Regional Meeting. SPE, 2022. http://dx.doi.org/10.2118/209264-ms.

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Abstract Stimulating source rocks using hydraulic fracturing in unconventional source rocks is a common process. But such practice has not been followed when dealing with tight reservoir rocks. Tight carbonate reservoir rocks have in general been subjected to multistage acid fracturing. This paper describes the analysis of actual performance data to acid fracturing in a tight carbonate formation and the ineffectiveness of the process as measured by the performance responses of the producing wells. The case study relates to a tight formation that is considered a reservoir rather than a source rock. The formation permeability is in the range of 0.1-5 millidarcies. Development has been through numerous horizontal wells with limited multistage acid stimulation. Analysis of performance data for more than 30 wells Indicates no fracture flow and very limited stimulated production. Different diagnostic methods were used to determine the nature of the flow regime and to examine the true benefit of multistage acid fracturing. Most of the wells studied show primarily a radial flow condition after limited acid fracturing. The main observation is that the process of acid fracturing at best has resulted in local near wellbore stimulation on all these wells, and there are no significant indications of fracture-dominated flow. Many of the wells also show early signs of the boundary effect that explains the ineffectiveness of the recovery process.
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Reports on the topic "Source rock reservoir"

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Bloch, J. Source-rock potential and reservoir characteristics of the lower (Albian-Turonian) Colorado Group, western Canada. Natural Resources Canada/ESS/Scientific and Technical Publishing Services, 1995. http://dx.doi.org/10.4095/203641.

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Finzel, E. S., R. R. Reifenstuhl, P. L. Decker, and K. D. Ridgway. Sedimentology, stratigraphy, and hydrocarbon reservoir-source rock potential, using surface and subsurface data, of Tertiary and Mesozoic strata, Bristol Bay Basin and Alaska Peninsula. Alaska Division of Geological & Geophysical Surveys, July 2005. http://dx.doi.org/10.14509/7184.

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Doctor, R. D., and T. L. Moore. The use of predictive lithostratigraphy to significantly improve the ability to forecast reservoir and source rocks? Final CRADA report. Office of Scientific and Technical Information (OSTI), June 2010. http://dx.doi.org/10.2172/982990.

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Lavoie, D., N. Pinet, S. Zhang, J. Reyes, C. Jiang, O. H. Ardakani, M. M. Savard, et al. Hudson Bay, Hudson Strait, Moose River, and Foxe basins: synthesis of Geo-mapping for Energy and Minerals program activities from 2008 to 2018. Natural Resources Canada/CMSS/Information Management, 2022. http://dx.doi.org/10.4095/326090.

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As part of its Geo-mapping for Energy and Minerals program, the Geological Survey of Canada included the Hudson Bay Basin in its research portfolio with the goal of generating a modern understanding of its geological framework and a precise knowledge of its hydrocarbon systems. The Hudson Bay-Foxe Basins GEM-1 project led to the proposal of modern stratigraphic frameworks and produced extensive geochemical data on hydrocarbon source rocks as well as data on diverse burial-thermal indicators. Satellite data were acquired over the entire offshore domain in the search for evidence for active hydrocarbon systems. For the Hudson-Ungava GEM-2 project, the aim of the research activities was to better understand local and regional factors associated with the burial and exhumation histories as they pertain to regional or local hydrocarbon prospectivity. This research led to a basin-scale stratigraphic framework coupled with detailed analyses of hydrocarbon generation and the appraisal of the best potential reservoir units.
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Bécu, V., A.-A. Sappin, and S. Larmagnat. User-friendly toolkits for geoscientists: how to bring geology experts to the public. Natural Resources Canada/CMSS/Information Management, 2022. http://dx.doi.org/10.4095/331220.

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A growing number of countries are committed toreduce their carbon emissions and are transitioning towards renewable and clean energy sources, leading to an in crease in demand formetals and minerals. This is especially the case for a short list of what are called "critical minerals" which are considered essential to economic development, including the transition to a low-carbon economy and national security. There liability of their supply chain raises concerns considering geological scarcity, difficulty to extract and/or political factors influencing their availability. At the same time, public awareness and perception of geoscience are eroding and there is more and more reluctance towards mining projects, even from traditionally favourable communities. To face this challenge, promote public interest and outline the contribution of geological science to society, geoscientists of the Geological Survey of Canada (GSC-Québec) have designed and put together a portable display that includes a suite of mineral and metal samples considered critical for the sustainable success of Canada's transition towards a clean and digital economy. The display is a user-friendly toolkit that can be used by any GSC geoscientists during outreach activities, in classrooms as well as during public open houses. It comes with straightforward pedagogic material and content, along with presentation scenarios. To broaden and adapt the workshops to specific expectations, additional toolkits were developed and all are contained within easy to carry travel cases. These cover a variety of topics and can be presented as stand-alone displays or be used complementary to one another. For example, the "Mines and minerals" collection may serve as a supplement to the "Critical minerals" display to present every day objects in which minerals are used as well as ores amples from active mines to illustrate the intertwining between mining activities and our everyday lives. Another display covers the ever-popular fossils thematic with the "Sedimentary rocks and fossils" collection and gives an opportunity to address key geoscience themes such as life evolution and biological crisis along with groundwater reservoirs and resources. The "Magmatic rocks" display touches on the formation of rocks from magmas, the different types and active processes of volcanoes, and discusses the risks and benefits related to volcanic activity. Hopefully, these four ready-to-use portable displays will encourage more GSC geoscientists to engage in public oriented activities to make geosciences more accessible, change perceptions and offer an overall tangible scientific experience for people.
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