scholarly journals Worldwide shale-oil reserves: towards a global approach based on the principles of Petroleum System and the Petroleum System Yield

2017 ◽  
Vol 188 (5) ◽  
pp. 33 ◽  
Author(s):  
Marc Blaizot
Keyword(s):  
Middle East ◽  
Source Rock ◽  
Oil Production ◽  
Petroleum System ◽  
Source Rocks ◽  
Recovery Factor ◽  
Shale Oil ◽  
Average Recovery ◽  
Oil Reserves ◽  
Oil Resources

Global inventory of shale-oil resources and reserves are far from being complete even in mature basins which have been intensively drilled and produced and in which the main parameters of the regional or local oil-prone source rocks are known. But even in these cases, difficulties still occur for deriving reserves from resources: reaching a plausible recovery factor is actually a complex task because of the lack of production history in many shale-oil ventures. This exercise is in progress in several institutions (EIA, USGS, AAPG) or private oil and gas companies on a basin-by-basin basis in order to estimate the global potential. This analytical method is very useful and accurate but also very time consuming. In the last EIA report in 2013 “only” 95 basins had been surveyed whereas for example, no Middle-East or Caspian basins have been taken into account. In order to accelerate the process and to reach an order of magnitude of worldwide shale-oil reserves, we propose hereafter a method based on the Petroleum System principle as defined by Demaison and Huizinga (Demaison G and Huizinga B. 1991. Genetic classification of Petroleum Systems. AAPG Bulletin 75 (10): 1626–1643) and more precisely on the Petroleum System Yield (PSY) defined as the ratio (at a source-rock drainage area scale) between the accumulated hydrocarbons in conventional traps (HCA) and hydrocarbons generated by the mature parts of the source-rock (HCG). By knowing the initial oil reserves worldwide we can first derive the global HCA and then the HCG. Using a proxy for amount of the migrated oil from the source-rocks to the trap, one can obtain the retained accumulations within the shales and then their reserves by using assumptions about a possible average recovery factor for shale-oil. As a definition of shale-oil or more precisely LTO (light tight oil), we will follow Jarvie (Jarvie D. 2012. Shale resource systems for oil & gas: part 2 – Shale Oil Resources Systems. In: Breyer J, ed. Shale Reservoirs. AAPG, Memoir 97, pp. 89–119) stating that “shale-oil is oil stored in organic rich intervals (the source rock itself) or migrated into juxtaposed organic lean intervals”. According to several institutes or companies, the worldwide initial recoverable oil reserves should reach around 3000 Gbo, taking into account the already produced oil (1000 Gbo) and the “Yet to Find” oil (500 Gbo). Following a review of more than 50 basins within different geodynamical contexts, the world average PSY value is around 5% except for very special Extra Heavy Oils (EHO) belts like the Orinoco or Alberta foreland basins where PSY can reach 50% (!) because large part of the migrated oils have been trapped and preserved and not destroyed by oxidation as it is so often the case. This 50% PSY figure is here considered as a good proxy for the global amount of expelled and migrated oil as compared to the HCG. Confirmation of such figures can also be achieved when studying the ratio of S1 (in-place hydrocarbon) versus S2 (potential hydrocarbons to be produced) of some source rocks in Rock-Eval laboratory measurements. Using 3000 Gbo as worldwide oil reserves and assuming a quite optimistic average recovery factor of 40%, the corresponding HCA is close to 7500 Gbo and HCG (= HCA/PSY) close to 150 000 Gbo. Assuming a 50% expulsion (migration) factor, we obtain that 75 000 Gbo is trapped in source-rocks worldwide which corresponds to the shale-oil resources. To derive the (recoverable) reserves from these resources, one needs to estimate an average recovery factor (RF). Main parameters for determining recovery factors are reasonable values of porosity and saturation which is difficult to obtain in these extremely fine-grained, tight unconventional reservoirs associated with sampling and laboratories technical workflows which vary significantly. However, new logging technologies (NMR) as well as SEM images reveal that the main effective porosity in oil-shales is created, thanks to maturity increase, within the organic matter itself. Accordingly, porosity is increasing with Total Organic Carbon (TOC) and paradoxically with… burial! Moreover, porosity has never been water bearing, is mainly oil-wet and therefore oil saturation is very high, measured and calculated between 75 and 90%. Indirect validation of such high figures can be obtained when looking at the first vertical producing wells in the Bakken LTO before hydraulic fracturing started which show a very low water-cut (between 1 and 4%) up to a cumulative oil production of 300 Kbo. One can therefore assume that the highest RF values of around 10% should be used, as proposed by several researchers. Accordingly, the worldwide un-risked shale-oil reserves should be around 7500 Gbo. However, a high risk factor should be applied to some subsurface pitfalls (basins with mainly dispersed type III kerogen source-rocks or source rocks located in the gas window) and to many surface hurdles caused by human activities (farming, housing, transportation lines, etc…) which can hamper developments of shale-oil production. Assuming that only shale-oil basins in (semi) desert conditions (i.e., mainly parts of Middle East, Kazakstan, West Siberia, North Africa, West China, West Argentina, West USA and Canada, Mexico and Australia) will be developed, a probability factor of 20% can be used. Accordingly, the global shale-oil reserves could reach 1500 Gbo which is half the initial conventional reserves and could therefore double the present conventional oil remaining reserves.

scholarly journals Geochemical evidence for a new Triassic petroleum system on the western margin of Australia

2021 ◽  
Vol 61 (2) ◽  
pp. 616
Author(s):  
Emmanuelle Grosjean ◽  
Dianne S. Edwards ◽  
Nadege Rollet ◽  
Christopher J. Boreham ◽  
Duy Nguyen ◽  
...  
Keyword(s):  
Middle Triassic ◽  
Lower Triassic ◽  
Petroleum System ◽  
Source Rocks ◽  
Type Ii ◽  
North West ◽  
Oil Resources ◽  
Isotopic Analyses ◽  
Potential Trap ◽  
The Phoenix

The unexpected discovery of oil in Triassic sedimentary rocks of the Phoenix South 1 well on Australia’s North West Shelf (NWS) has catalysed exploration interest in pre-Jurassic plays in the region. Subsequent neighbouring wells Roc 1–2, Phoenix South 2–3 and Dorado 1–3 drilled between 2015 and 2019 penetrated gas and/or oil columns, with the Dorado field containing one of the largest oil resources found in Australia in three decades. This study aims to understand the source of the oils and gases of the greater Phoenix area, Bedout Sub-basin using a multiparameter geochemical approach. Isotopic analyses combined with biomarker data confirm that these fluids represent a new Triassic petroleum system on the NWS unrelated to the Lower Triassic Hovea Member petroleum system of the Perth Basin. The Bedout Sub-basin fluids were generated from source rocks deposited in paralic environments with mixed type II/III kerogen, with lagoonal organofacies exhibiting excellent liquids potential. The Roc 1–2 gases and the Phoenix South 1 oil are likely sourced proximally by Lower–Middle Triassic TR10–TR15 sequences. Loss of gas within the Phoenix South 1 fluid due to potential trap breach has resulted in the formation of in-place oil. These discoveries are testament to new hydrocarbon plays within the Lower–Middle Triassic succession on the NWS.

scholarly journals Investigating the Oil Effect on the Politicking in the 19th August, 1953 Coup d'État

2016 ◽  
Vol 69 ◽  
pp. 25-31
Author(s):  
Seid Mohamad Reza Mahmodpanahi ◽  
Sosan Shokriaghkand
Keyword(s):  
United States ◽  
Middle East ◽  
The United States ◽  
Oil Reserves ◽  
National Movement ◽  
Oil Resources

The strategic situation of Iran has always drawn the attention of foreign powers including England, Russia and America and these powers have always attempted to utilize this situation for reaching their own interests in the Middle East. Discovery of large oil reserves in Iran intensified the competition of foreign powers. This research seeks to respond the question of how foreign powers intervened with the 19th August, 1953 Coup d'état. In the 19th August, 1953 Coup d'état, the Americans and English having after made sure that they could not seize the Iranian oil through political channels, they decide to launch a Coup d'état. With the victory of the 19th August, 1953 Coup d'état and subversion of the Dr. Mosadegh's government, the United States and Britain consolidated their own dominate in Iran via returning Mohamad Reza Shah and the oil reserves were once again made available to foreign powers. This research via applying comparative-descriptive methodology is based on documents and evidence. Findings of the research and examination of the 19th August, 1953 Coup d'état demonstrate that the significance of oil and energy and fear of the spread of the Oil National Movement to other oil producing countries and compromise of oil resources as well resulted in intervention by cross regional foreign powers like England, America with respect to the 19th August, 1953 Coup d'état.

New perspectives on the source rock facies of the Andaman Trough, offshore North Sumatra based on the latest onshore oil sampling and analysis

2021 ◽  
Author(s):  
D. Ariyono
Keyword(s):  
Source Rock ◽  
Pour Point ◽  
Petroleum System ◽  
Source Rocks ◽  
Late Oligocene ◽  
Administrative District ◽  
Stratigraphic Framework ◽  
Lacustrine Source Rock ◽  
Wax Content ◽  
North Sumatra

The Andaman sub-basin, located offshore Aceh Indonesia, is considered to be one of Indonesia’s most underexplored basins, despite its proximity to the giant gas and condensate fields of Arun, NSO A, NSO J and South Lhok Sukon, where in excess of 6 MMboe has been produced to date. The understanding of the Petroleum System in the offshore Andaman Trough, has historically been challenged by poor imaging of the basin architecture and limited penetration and retrieval of source rock intervals and hydrocarbon fluids for analysis. Mubadala Petroleum, as operator of the Andaman I PSC, conducted a geological field study to collect multiple oil samples from fourteen (14) onshore traditional wells across the Bireun and Aceh Timur Administrative District (Figure 1). Those samples were analyzed in laboratory for their physical properties and parameters derived from those analyzes where integrated to fully characterize oils produced in the onshore Aceh area and establish the organofacies and maturity of their source facies precursors. The results were then used as calibration for the analysis and subsurface modeling of the offshore petroleum system of the Andaman sub-basin. Previous authors have postulated that Late Oligocene to Early Miocene marine shales were the main source rocks for oil in the Andaman Trough. Oil samples collected onshore as part of this study however, were sourced by peak to late mature oil-prone lacustrine source rock facies, yielding high API (42.7 – 50.8°), low pour point, low sulphur, and low wax content fluids. Integration of these findings with the upgraded tectono-stratigraphic framework provided by the 2019 MC3D survey, reprocessed multi-vintage 2D, and reinterpretation of biostratigraphic analysis, has enabled the delineation of a postulated Paleogene lacustrine source rock facies in the Andaman Trough. This model does not preclude the potential of other source rock facies to be present and active within the Andaman Trough, including the gas-prone fluvial Eocene-Oligocene Parapat Formation, but it supports the possibility that oil may have been generated in the Andaman Trough.

The Evaluation of Potential of Shale Oil Resources in K1qn1 Formation of Southern Songliao Basin

2014 ◽  
Vol 1006-1007 ◽  
pp. 107-111
Author(s):  
Yan Wang ◽  
Wen Biao Huang ◽  
Min Wang
Keyword(s):  
Organic Matter ◽  
Source Rock ◽  
Thermal Evolution ◽  
Songliao Basin ◽  
Mature Stage ◽  
Type I ◽  
Hydrocarbon Generation ◽  
Shale Oil ◽  
Oil Resources ◽  
Geochemical Method

Based on the analysis of source rock geochemical index, with K1qn1 Formation of southern Songliao basin as the research objective layer, it’s concluded that the mean TOC value of shale in K1qn1 Formation is higher, generally more than 1%, which belongs to the best source rock. Most of shale organic matter types are type I and type II1. The thermal evolution degree of organic matter is generally in the mature stage: a stage of large hydrocarbon generation. With logging geochemical method applied, the calculated total resources of shale oil in K1qn1 formation are 15.603 billion tons. The II level of resources are 8.765 billion tons, which is more than 50% of the total resources. The I level of resources are 4.808 billion tons while the III level of resources 2.03 billion tons. Overall, the southern Songliao Basin still has a certain degree of prospecting and mining value.

scholarly journals The Upper Jurassic–Cretaceous petroleum system of southern Iraq: A 3-D basin modelling study

GeoArabia ◽  
2013 ◽  
Vol 18 (1) ◽  
pp. 179-200
Author(s):  
Qusay Abeed ◽  
Ralf Littke ◽  
Frank Strozyk ◽  
Anna K. Uffmann
Keyword(s):  
Source Rock ◽  
Lower Cretaceous ◽  
Upper Jurassic ◽  
Petroleum System ◽  
Source Rocks ◽  
Maximum Temperature ◽  
Basin Modelling ◽  
Petroleum Generation ◽  
D Model ◽  
Southern Iraq

ABSTRACT A 3-D basin model of the southern Mesopotamian Basin, southern Iraq, was built in order to quantify key aspects of the petroleum system. The model is based on detailed seismic interpretation and organic geochemical data, both for source rocks and oils. Bulk kinetic analysis for three source rock samples was used to quantify petroleum generation characteristics and to estimate the temperature and timing of petroleum generation. These analyses indicate that petroleum generation from the Yamama source rock (one of the main source rocks in the study area) starts at relatively low temperatures of 70–80°C, which is typical for Type II-S kerogen at low to moderate heating rates typical of sedimentary basins. Petroleum system analysis was achieved using the results from 1-D, 2-D, and 3-D basin modelling, the latter being the major focus of this study. The 1-D model reveals that the Upper Jurassic–Lower Cretaceous sediments are now within the oil window, whereas the formations that overlie the Yamama Formation are still immature in the entire study area. Present-day temperature reflects the maximum temperature of the sedimentary sequence, which indicates that no strong regional uplift affected the sedimentary rocks in the past. The 3-D model results indicate that oil generation in the Yamama source rock already commenced in the Cretaceous. At some locations of the basin this source rock reaches a present-day maximum temperature of 140–150°C. The most common migration pathways are in the vertical direction, i.e. direct migration upward from the source rock to the reservoir. This is partly related to the fact that the Lower Cretaceous reservoir horizons in southern Iraq directly overlay the source rock.

scholarly journals Organic matter heterogeneity and shale oil significance in Triassic Zhangjiatan shale, Ordos Basin, China

2021 ◽  
pp. 014459872110393
Author(s):  
Xiaoyan Li ◽  
Jincai Tuo ◽  
Chenjun Wu ◽  
Honggang Xin ◽  
Mingfeng Zhang ◽  
...  
Keyword(s):  
Organic Matter ◽  
Vertical Profile ◽  
Sedimentary Environment ◽  
Ordos Basin ◽  
Immature Stage ◽  
Source Rocks ◽  
Organic Carbon Content ◽  
Shale Oil ◽  
Oil Resources ◽  
Geochemical Analyses

Organic matter heterogeneity exerts an important impact on the generation, evaluation, and exploitation of shale oil resources. In the past, only a limited number of analytical samples that represented the contribution or influence of high or low organic matter abundance intervals were used to represent an entire set of thick source rocks, and based on this limitation, occasionally researchers have reached incorrect conclusions. Here, the heterogeneity of organic matter and its significance to shale oil in the Triassic Zhangjiatan shale of the Ordos Basin were discussed based on sedimentary and geochemical analyses. Our results indicate that (1) the Chang 73 shale within the study area is characterized by high abundance, good quality, strong heterogeneity, and segmented enrichment in the vertical profile. The primary organic matter type was type II1, and this was followed by types I, II2, and III that exhibited three changing trends in the vertical profile. Organic matter maturity is primarily at the immature stage. (2) Additionally, we observed that the organic matter heterogeneity of Chang 73 shale was related to changes in lithology, sedimentary environment, paleoproductivity, terrigenous influence, and event action (such as volcanism and hydrothermal processes). The abundance of organic matter is the result of the coupling control of these processes. In the process of organic matter deposition, if volcano or hydrothermal activities occurred, the organic matter was abnormally enriched, and the total organic carbon content exceeded 20% and could even be as high as 40%. (3) Finally, we observed at least nine enrichment layers that were controlled by the coupling of different geological factors, and there were four potential target resource layers corresponding to the hydrothermal sedimentary area.

Unconventional Shale Play in Oman: Preliminary Assessment of the Shale Oil / Shale Gas Potential of the Silurian Hot Shale of the Southern Rub al-Khali Basin

2015 ◽  
Author(s):  
Jamal A. Madi ◽  
Elhadi M. Belhadj
Keyword(s):  
Source Rock ◽  
Shale Gas ◽  
Oil And Gas ◽  
Source Rocks ◽  
Geochemical Data ◽  
Hydrocarbon Generation ◽  
Shale Oil ◽  
Lower Silurian ◽  
History Of ◽  
Oil Gas

Abstract Oman's petroleum systems are related to four known source rocks: the Precambrian-Lower Cambrian Huqf, the Lower Silurian Sahmah, the Late Jurassic Shuaiba-Tuwaiq and the Cretaceous Natih. The Huqf and the Natih have sourced almost all the discovered fields in the country. This study examines the shale-gas and shale-oil potential of the Lower Silurian Sahmah in the Omani side of the Rub al Khali basin along the Saudi border. The prospective area exceeds 12,000 square miles (31,300 km2). The Silurian hot shale at the base of the Sahmah shale is equivalent to the known world-class source rock, widespread throughout North Africa (Tannezouft) and the Arabian Peninsula (Sahmah/Qusaiba). Both thickness and thermal maturities increase northward toward Saudi Arabia, with an apparent depocentre extending southward into Oman Block 36 where the hot shale is up to 55 m thick and reached 1.4% vitrinite reflectance (in Burkanah-1 and ATA-1 wells). The present-day measured TOC and estimated from log signatures range from 0.8 to 9%. 1D thermal modeling and burial history of the Sahmah source rock in some wells indicate that, depending on the used kinetics, hydrocarbon generation/expulsion began from the Early Jurassic (ca 160 M.a.b.p) to Cretaceous. Shale oil/gas resource density estimates, particularly in countries and plays outside North America remain highly uncertain, due to the lack of geochemical data, the lack of history of shale oil/gas production, and the valuation method undertaken. Based on available geological and geochemical data, we applied both Jarvie (2007) and Talukdar (2010) methods for the resource estimation of: (1) the amount of hydrocarbon generated and expelled into conventional reservoirs and (2) the amount of hydrocarbon retained within the Silurian hot shale. Preliminary results show that the hydrocarbon potential is distributed equally between wet natural gas and oil within an area of 11,000 square mile. The Silurian Sahmah shale has generated and expelled (and/or partly lost) about 116.8 billion of oil and 275.6 TCF of gas. Likewise, our estimates indicate that 56 billion of oil and 273.4 TCF of gas are potentially retained within the Sahmah source rock, making this interval a future unconventional resource play. The average calculated retained oil and gas yields are estimated to be 6 MMbbl/mi2 (or 117 bbl oil/ac-ft) and 25.3 bcf/mi2 (or 403 mcf gas/ac-ft) respectively. To better compare our estimates with Advanced Resources International (EIA/ARI) studies on several Silurian shale plays, we also carried out estimates based on the volumetric method. The total oil in-place is 50.2 billion barrels, while the total gas in-place is 107.6 TCF. The average oil and gas yield is respectively 7 MMbbl/mi2 and 15.5 bcf/mi2. Our findings, in term of oil and gas concentration, are in line or often smaller than all the shale oil/gas plays assessed by EIA/ARI and others.

scholarly journals Oil Production by Polish Companies in Poland and Abroad

2020 ◽  
Vol 2 (1) ◽  
Author(s):  
Tadeusz OLKUSKI ◽  
Janusz ZYŚK ◽  
Barbara TORA ◽  
Wacław ANDRUSIKIEWICZ ◽  
Adam SZURLEJ ◽  
...  
Keyword(s):  
Oil Production ◽  
Modern World ◽  
The Baltic Sea ◽  
Oil Reserves ◽  
The Carpathians ◽  
Oil Resources ◽  
Carpathian Foredeep ◽  
Oil Deposits ◽  
Economic Zone ◽  
The Baltic

The article discusses a very important problem of oil production. Oil, recognized as a major source of economic development, is themain energy source of the modern world. Unfortunately, Poland has limited oil reserves. However, the production, which meets onlyabout 4% of the demand, is carried out. Oil deposits in Poland are found in the Carpathians, in the Carpathian Foredeep, in the Polish Lowlands, and in the Polish Exclusive Economic Zone of the Baltic Sea. Initially, deposits in the Carpathians were of the greatesteconomic importance, but these are already depleted to a great extent. Currently, oil deposits in the Polish Lowlands are of the greatesteconomic importance. The largest deposit is BMB (Barnówko-Mostno-Buszewo) near Gorzów Wielkopolski. In total, in Poland oilresources amount to 23 598.46 thousand tons, of which 61.37% accounts for industrial resources (14 482.15 thousand tons). The article presents crude oil resources in Poland by regions, i.e. Polish Lowlands, the Carpathians, the Carpathian Foredeep, and the PolishExclusive Economic Zone The resources were divided into anticipated economic, industrial, undeveloped resources and abandoneddeposits. In addition, the three Polish companies involved in the extraction of oil, namely PGNiG S.A., the LOTOS Group S.A. andORLEN Upstream sp. z o.o., were presented. The locations where exploitation is carried out and the volume of oil production in thelast few years were discussed.

scholarly journals ADVANCES ON THE GEOLOGY AND EVALUATION OF POTENTIAL PETROLEUM SYSTEMS OF THE SOKOTO BASIN IN NW NIGERIA

2020 ◽  
Vol 1 (2) ◽  
Keyword(s):  
Source Rock ◽  
Current Knowledge ◽  
Petroleum System ◽  
Source Rocks ◽  
Tectonic Structures ◽  
Reservoir Rocks ◽  
Petroleum Systems ◽  
Potential Reservoir ◽  
Geochemical Studies ◽  
Controlled Structures

The stratigraphy of the Sokoto Basin has the Illo/Gundumi Formation at the bottom, followed successively upward by the Taloka, Dukamaje, Wurno, Dange, Kalambaina, Gamba and Gwandu Formations. Re-mapping of the basin carried out in this study shows that the geological framework remains largely as previously outlined except that some hitherto unreported tectonically controlled structures have been documented. The basin is generally shallower at the margin and deepens towards the centre such that the areas around the border with Niger Republic are deepest and hence most prospective on the Nigerian side. Geophysical aeromagnetic interpretation has assisted to analyze the depth to basement configurations. Organic geochemical studies show that the dark shales and limestones of the Dukamaje Formation constitute the source rocks in the potential petroleum system. With averages for source rock thickness of 50m, area of basin of 60,000km2, TOC of 7.5wt%, and HI of 212mgHC/gTOC, charge modeling indicates 808.10 million barrels of oil equivalent extractable hydrocarbons in the Sokoto Basin, at current knowledge of the geology and if the appropriate maturity has been attained at deeper sections. The sandstones of the Illo/Gundumi Formation as well as in the Taloka and Wurno Formations and carbonates of the Kalambaina Formation provide potential reservoir packages. The paper shale of the Gamba Formation and the clays of the Gwandu Formation provide regional seals. If the presently mapped tectonic structures are ubiquitous in the whole basin, structural and stratigraphic traps may upgrade the petroleum system. Other petroleum systems may exist in the basin with either or both the Illo/Gundumi and Taloka Formation(s) providing the source and reservoir rocks. Keywords: Sokoto Basin, Dukamaje Formation, Hydrocarbons, Petroleum System, Reservoirs

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