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THE MODERN OIL INDUSTRY IN IRAN: A HISTORICAL PERSPECTIVE AND REVIEW

The production of petroleum substances has a long historical tradition in Iran. Glance (1970) reported that the “first man‐made oil well was dug” in the ancient city of Susa (present‐day Shush), about 40 km northwest of Ahwaz, in 500 BC during the reign of the Achaemenid emperor Darius I. Writing in the fifth century BC, Herodotus described petroleum production near a place called Ardericca, probably present‐day Masjed Soleyman, located 210 furlongs from Susa (Lees, 1950). The petroleum substances produced included bitumen which was used in construction and the waterproofing of ships. Sorkhabi (2005) detailed the petroleum history in Iran during ancient and medieval times.The modern quest for oil in Iran dates from the second half of the 19th century. From a historical perspective, this modern period can be divided into six distinct phases: (i) The early years, 1872–1900; (ii) The Anglo‐Persian years, 1901–1932; (iii) The Anglo‐Iranian Years and Nationalization, 1933–1953; (iv) The second Pahlavi years, 1954–1978 including the rise of OPEC; (v) The Islamic Revolution and Iran‐Iraq War, 1979–1989; and (vi) Buyback Contracts and US Sanctions, 1990–Present. The search for oil was singularly unsuccessful during the first of these phases and the early years of the second phase. However, after a difficult six‐year exploration campaign, oil in commercial quantities was struck in the early hours of 26 May, 1908 at Maidan‐e Naftun, which in later years achieved world fame as the Masjed Soleyman oil field. Since then, more than 120 oil and gas field discoveries have been made in Iran's onshore areas and its territorial waters in the Persian Gulf.The story of oil has always been an emotive and politically charged issue in Iran and has been the focus of great national interest and debate for over a century. Certainly, the discovery in 1908 marked a milestone in Iran's 20th century history: it ushered in a new era – an era not only of progress and prosperity, but also of social and political upheaval and turmoil that has not yet ended (Ala, 2007). In this paper, important events in each of the historical phases identified above are briefly reviewed. Emphasis is placed on the emergence of the modern petroleum industry in Iran, and the early phases are covered in particular detail.

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PALYNOFACIES AND ORGANIC GEOCHEMISTRY OF LACUSTRINE SOURCE ROCKS: THE POTRERILLOS – CACHEUTA SOURCE ROCK SYSTEM IN THE TRIASSIC CUYO BASIN, WEST‐CENTRAL ARGENTINA

This study presents an integrated investigation of the Upper Triassic Potrerillos – Cacheuta lacustrine source rock in the Cuyo Basin of western Argentina. Data came from palynofacies analyses, organic petrography, Rock‐Eval pyrolysis and mineralogical studies based on X‐ray diffraction analyses. An 80 m thick outcrop section was studied and is interpreted to represent the transition from shallow‐lacustrine sediments influenced by fluvial discharges (uppermost Potrerillos Formation) to the deposits of a deep, permanent lake (Cacheuta Formation). Three palynofacies were defined. Palynofacies I is characterized by shallowing‐upward cycles with abundant woody material, and was deposited under an oxic, disturbed water column. Palynofacies II and III occur in laminated shales rich in amorphous organic matter (AOM) and freshwater algal material (Botryococcus) respectively, which were deposited under oxygen‐depleted conditions. In general, the detrital material present suggests an input derived from fluvial discharges; however, interbedded tuffs altered to analcime and smectite suggest the transformation of vitric material in pyroclastic ash under saline to alkaline water conditions. Kerogen Types II/III and III with high total organic carbon values indicate a moderate oil‐ and gas‐prone source rock whose thermal maturity varies from immature to the early oil window (Tmax: 430‐438 °C; vitrinite reflectance: 0.59‐0.67 % VRo; and thermal alteration index: 2‐2+).This study demonstrates the importance of palynofacies analyses for the interpretation of depositional changes and associated controls in lacustrine shale successions. When integrated with data from organic geochemistry, palynofacies analysis is an important tool in the evaluation of a source rock's thermal maturity and hydrocarbon generation potential.

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STRUCTURAL STYLE AND TIMING OF NW‐SE TRENDING ZAGROS FOLDS IN SW IRAN: INTERACTION WITH NORTH‐SOUTH TRENDING ARABIAN FOLDS AND IMPLICATIONS FOR PETROLEUM GEOLOGY

The Zagros foldbelt – foreland system in SW Iran is a prolific hydrocarbon province with known reserves of more than 90 billion brl of oil and 800 TCF of natural gas. Establishing the structural style of folding in the Zagros area presents a major challenge due both to the geographical extent of the foldbelt, which is some 1600 km long in total, and the presence of marked lateral variations in fold style related to the complex regional tectonic history. In addition, while numerous high‐quality structural studies of the Zagros have been completed over the last 20 years, they support a variety of different interpretations and are therefore diffcult to synthesize. In this paper, we review the general structural style of the Zagros fold‐and‐thrust belt in SW Iran, and in particular the style of folding in the Lurestan arc, Dezful embayment, Izeh Zone and Fars arc. We summarise relationships between folding in these areas and fracture development, and investigate the timing of folding and the interaction between NW‐SE oriented “Zagros” folds and north‐south oriented “Arabian” folds. Finally, we briefly assess the implications of fold style for petroleum systems in the Zagros area. Although no new data are presented in this paper, a series of unpublished maps are used to illustrate the main results and include: a map showing the extent of the main detachment levels across the Lurestan, Dezful and Fars structural domains; two palaeotectonic maps (for Late Cretaceous – Paleocene and Miocene – Pliocene times, respectively), showing the position of the deformation fronts of the Zagros and the North Oman thrust systems and their potential spatial and temporal relationship with folding; and a set of four maps showing the distribution of reservoir rocks which are grouped by age into the Permian – Triassic Dehram Group, the Late Jurassic – Early Cretaceous Khami Group, the Late Cretaceous Bangestan Group, and the Oligocene – Miocene Asmari Formation. In addition, for the Lurestan, Dezful and Fars structural domains, a series of regional cross‐sections at the same scale are presented and discussed.Most of the data in this review paper were acquired in order to gain an improved understanding of the petroleum systems in the Zagros area; however the data are used here to investigate a range of interacting processes including tectonics, sediment deposition and subsurface fluid flow in the development of the fold‐and‐thrust belt and its associated foreland basins. The resulting synthesis is intended to provice a starting point for future tectonostratigraphic and hydrocarbon‐related studies which will make use of both existing and new multidisciplinary techniques to constrain the results. The knowledge acquired and the techniques used will be of benefit in future challenges including the identification of subsurface reservoirs suitable for the permanent storage of CO2 to mitigate the effects of climate change.

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PETROGRAPHY OF PYROBITUMENS IN MIDDLE – LATE JURASSIC SANDSTONES FROM THERMALLY DEGRADED HYDROCARBON ACCUMULATIONS, EAST GREENLAND

A number of exhumed hydrocarbon traps have been described from the Traill Ø region of East Greenland. This study focuses on the Bjørnedal area where the distribution of bitumen has been mapped out. Bitumen staining clearly has a cross‐cutting relationship to stratigraphic units and can be shown to form distinct palaeo‐accumulations. Detailed petrographic studies show that bitumen occurs as late diagenetic phases in Middle to Late Jurassic sandstones, and is present both as both grain‐coating and pore‐filling phases. Geochemical analyses confirm that the bitumen is organic in composition and is composed largely of carbon and hydrogen. Both H/C ratios and bonds identified by FTIR behave as expected with increasing maturity measured using bitumen reflectance. Together, these results provide strong evidence that the material is pyrobitumen derived from the in situ thermal degradation of a liquid hydrocarbon precursor. On the basis of textures in transmitted and reflected light and quantitative bitumen reflectance distributions, two populations of pyrobitumen may be recognised in some samples.Two phases of Paleogene magmatism occurred in the Traill Ø region. The first late Paleocene – early Eocene phase was related to the opening of the northern North Atlantic in the earliest Eocene, and was experienced throughout East Greenland and the northwest European margin. The later magmatic phase was related to the gradual separation of the Jan Mayen microcontinent from East Greenland through the late Eocene – early Oligocene. A single pyrobitumen phase is recognised in accumulations only affected by the early magmatism, and a second phase is only observed in areas affected by both the early and later magmatism. This relationship is interpreted as evidence for a direct relationship between magmatic phases and bitumen generation. The presence of bitumen formed by the thermal degradation of liquid hydrocarbons during the later magmatic event suggests that a viable petroleum system remained active following the early magmatic event.

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PRE‐, SYN‐ AND POST‐TECTONIC DIAGENETIC EVOLUTION OF A CARBONATE RESERVOIR: A CASE STUDY OF THE LOWER CRETACEOUS FAHLIYAN FORMATION IN THE DEZFUL EMBAYMENT, ZAGROS FOLDBELT, SW IRAN

Lower Cretaceous carbonates of the Fahliyan Formation form prolific reservoir rocks at oilfields in the Dezful Embayment, central Zagros fold‐thrust belt, SW Iran. The carbonates have undergone significant diagenetic alteration in phases which can in general be linked to the pre‐, syn‐ and post‐tectonic evolution of the fold‐thrust belt. This paper investigates the impact of diagenetic processes on the reservoir quality of the carbonates using integrated petrographic, geochemical and sedimentological analyses of subsurface and outcrop samples of the formation. Diagenetic alterations include:(i) pre‐tectonic eogenesis in the marine and shallow‐burial realm, which resulted in micritization of allochems and cementation by equant and isopachous calcite rims and framboidal pyrite together with limited dolomitization and dissolution of metastable bioclasts. The isotopic compositions of micrite and early calcite cement depart from postulated values of Lower Cretaceous marine carbonates, signifying early stabilization of precursor metastable carbonate minerals and the possible effects of the incursion of meteoric waters and/or increasing burial temperatures;(ii) mesogenesis during the subsequent syn‐tectonic phase, which included Late Cretaceous ophiolite obduction at the northern margin of the Arabian Plate and the later Zagros orogeny in the Miocene‐Pliocene. Diagenetic modifications included the emplacement of hydrocarbons, the development of stylolites and fractures, and the precipitation of saddle dolomite, replacive rhombic dolomite, discrete pyrite, microcrystalline quartz, kaolin and anhydrite. The average stable isotope compositions of saddle dolomite (δ18O: ‐6.9 ‰ ± .9 and δ13C 0.5 ‰ ± 1.6, respectively) also reflects the influence of high temprature basinal fluids;and (iii) “late” (telogenetic, post‐tectonic) uplift‐related modification starting in the Pliocene, when the incursion of meteoric waters resulted in the formation of vugs, the calcitization of dolomite, and cementation by fracture‐filling blocky calcite. The negative δ18O and δ13C stable isotope values (average: ‐5.5 ‰ ± 1.5; and ‐3.6 ‰ ± 5.9, respectively) of late blocky calcite cement suggest the incursion of meteoric water into the system.This study demonstrates that diagenetic processes in carbonates in the Fahliyan Formation, which exerted a significant control on the distribution of secondary porosity, can be related to the tectonic evolution of the central Zagros fold‐thrust belt. Thus, constraining the diagenetic history of carbonate successions within the context of their wider tectonic evolution is important for the prediction of the spatial and temporal distribution of reservoir quality.

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JURASSIC PETROLEUM SYSTEMS IN THE LUSITANIAN BASIN, PORTUGAL: NEW INSIGHTS BASED ON OIL – SOURCE ROCK CORRELATIONS

New stable carbon isotope and biomarker data for oils and source rock extracts from the Lusitanian Basin, Portugal, were studied in order to investigate the petroleum systems which are present there. The new analytical data was combined with data presented in previous publications, and oil‐oil and oil‐ source rock correlations were carried out. Three genetic groups of oils (Groups 1, 2 and 3), belonging to three different petroleum systems, were identified:Group 1 oils occur in the northern sector of the Lusitanian Basin and were generated by the Coimbra Formation (Sinemurian) source rock. Reservoir rocks for oils in this group are the Coimbra, Água de Madeiros (upper Sinemurian – lower Pliensbachian), Boa Viagem (Kimmeridgian –Tithonian) and Figueira da Foz (upper Aptian – Cenomanian) Formations. Other potential source rocks in the northern sector of the basin, such as the Polvoeira Member of the Água de Madeiros Formation and the Marly Limestones with Organic Facies (MLOF) Member of the Vale das Fontes Formation (Pliensbachian), had biomarker characteristics which differed from those of the Group 1 oils and did not therefore generate them.Group 2 oils occur in the central and southern sectors of the basin. The source rock is the Cabaços Formation (middle Oxfordian), and reservoir rocks are the Montejunto (middle‐upper Oxfordian) and Abadia (Kimmeridgian) Formations.Group 3 is represented by an oil sample from the central sector of the Lusitanian Basin. Both the source rock and the reservoir rock for the oil are the Montejunto Formation.Geochemical data combined with the regional tectono‐stratigraphic history suggest that the generation‐migration‐accumulation of most of the oil (critical moment) in the Coimbra – Coimbra ‐ Água de Madeiros ‐ Boa Viagem ‐ Figueira da Foz (!) petroleum system occurred in the early Campanian. For the Cabaços – Montejunto ‐ Abadia (!) and Montejunto – Montejunto (!) petroleum systems, the critical moment occurred in the late Cenomanian.

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A SYNTHESIS OF THE GEOLOGY AND PETROLEUM GEOLOGY OF THE IRANIAN PORTION OF THE SOUTH CASPIAN BASIN AND SURROUNDING AREAS

The South Caspian Basin, the northern Alborz Mountains, the Gorgan plain and the Moghan plain constitute the northernmost and youngest petroleum system in Iran. This region was part of the Paratethys realm from Oligocene to Pliocene time. The Oligocene – Miocene Maikop/Diatom Total Petroleum System of the South Caspian Basin produces major volumes of hydrocarbons in Azerbaijan and Turkmenistan, and the Iranian sector of the basin has consequently undergone exploration due to its generally similar geology. The 20 km thick, dominantly Cenozoic sedimentary cover in the basin is reduced to less than 3 km in the northern foothills of the Alborz Mountains, and scattered surface oil seepages in the latter region are believed to be generated by Cretaceous and Miocene source rocks. In the Moghan plain to the southwest of the South Caspian Basin, anticlinal folds of Oligo‐Miocene Zivar Formation sandstones may be prospective for hydrocarbon exploration. Mud volcanoes in the Gorgan plain and in adjacent offshore regions at the SE margin of the South Caspian Basin are associated with hydrocarbon seepages, and appear to be sourced by Cretaceous and Cenozoic shales and mudstones. Major structural features in the southern part of the South Caspian Basin include Cenozoic mud diapirs, folds and gravity structures.

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THE UPPER PERMIAN ZECHSTEIN SUPERGROUP OF NE ENGLAND AND THE ADJACENT SOUTHERN NORTH SEA: A REVIEW OF ITS ROLE IN THE UK'S ENERGY TRANSITION

As the United Kingdom reduces its CO2 emissions in order to meet its 2050 net zero greenhouse gas targets, there will be a significant evolution of the UK's energy mix. The reliance on hydrocarbons will decrease while there is predicted to be an increase in low carbon energy sources such as renewables and nuclear. In order to decarbonise and achieve the net zero emissions targets while concurrently producing enough energy to provide for national energy needs, large‐scale, low carbon energy generation projects need to be developed alongside energy storage facilities to provide flexibility within a low carbon energy supply. Robust CCUS programmes will need be developed in order to capture and store unavoidable carbon dioxide emissions. The subsurface geology of the UK provides opportunities for the development of low carbon energy generation, energy storage and CCS, and the Upper Permian Zechstein Supergroup deposited in eastern England and offshore in the Southern North Sea is a potential host for these new developments. In NE England, salt cavern gas storage sites have been developed in thick Zechstein evaporites since the mid 20th centrury. In this paper we present new isopach maps and well correlation panels which will help to outline optimal locations for the development of additional salt caverns for gas storage. A review of the Zechstein Supergroup indicates that it does not exhibit great potential for the development of CCS, due both to its complex reservoir characteristics and to difficulties with both subsurface imaging and monitoring. However thick Zechstein evaporites could provide an excellent seal for CO2 storage in the underlying Lower Permian Rotliegend Group.

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ORIGIN OF OIL IN UPPER PERMIAN (ZECHSTEIN) CARBONATE RESERVOIR ROCKS AT THE JARVIS STRUCTURE UNDERLYING THE ETTRICK FIELD, OUTER MORAY FIRTH, UK NORTH SEA

Oil in the Jarvis structure underlying the main Upper Jurassic reservoir at the Ettrick oilfield (Outer Moray Firth, UK northern North Sea) is present in Upper Permian (Zechstein) carbonates. The origin of this “Jarvis oil” is investigated in this paper using a multidisciplinary approach based on data from well‐logs and cores from wells 20/02‐2 and 20/02‐3. Reservoirs at the Jarvis structure consist of carbonates in the upper part of the Halibut Carbonate Formation (Ca2) and in the Carbonate Member of the Turbot Anhydrite Formation (Ca3). These carbonates are typical Zechstein dolomites composed of a range of facies from mudpackstones with storm beds deposited at moderate water depths to shoreface bioclastic‐oolitic packstones to shallow‐subtidal and intertidal microbial laminites. Interbedded anhydrites replace sabkha and lagoonal selenitic gypsum. Several shallowing‐upward units are recognised. Molecular analysis of the Jarvis oil, and comparisons with biomarker and other geochemical data from extracts of Zechstein cores and published data from different source rocks from the North Sea area, suggest that the oil was generated by marine, OM‐rich shales in the Upper Jurassic Kimmeridge Clay Formation. The oil was generated at peak oil window maturity and is characterised by high Pr/Ph, BNH/H and DBT/P ratios, and abundant C28 steranes and C28+29 monoaromatic and C26R + C27S triaromatic steroids. The molecular composition of organic material in extracts of core samples of Zechstein carbonates from wells in the Jarvis structure differs significantly from that of the Jarvis oil. Biomarkers such as BNH are absent in the core extracts, and there are different distributions and abundances of saturated and aromatic hydrocarbons, likely controlled by thermal maturity.

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