scholarly journals Geochemical evaluation of Khami Group oils in the South Dezful Embayment, Iran

2020 ◽  
Vol 10 (8) ◽  
pp. 3241-3254
Author(s):  
Bahram Alizadeh ◽  
Amir Abbas Jahangard ◽  
Majid Alipour ◽  
Ahmadreza Gandomi Sani
Keyword(s):  
Organic Matter ◽  
Stable Carbon Isotope ◽  
Upper Jurassic ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
The South ◽  
Dezful Embayment ◽  
Geochemical Evaluation ◽  
Diagnostic Characteristics ◽  
Kazhdumi Formation

Abstract An integrated geochemical study, including GC, GC–MS and stable carbon isotope analyses, was conducted on a suite of oil samples from the Khami Group reservoirs to provide new insights into the Upper Jurassic–Lower Cretaceous petroleum system in the South Dezful Embayment. Possible source rocks were also characterized using Rock–Eval pyrolysis to address the likely potential source rocks. The oil samples representing four major reservoirs (Surmeh, Fahliyan, Gadvan and Dariyan) constitute a single genetic oil family according to bulk and biomarker parameters. High API (> 38°), highly saturated hydrocarbons (Sat > 65%), very low asphaltene content (Asp < 2%) and raised saturates/aromatics ratio (Sat/Aro > 2) are the bulk diagnostic characteristics of the studied oils implying more dominant terrigenous nature of the precursor organic matter. The predominance of C29 regular steranes (~ 40%), presence of C29Ts as well as very low gammacerane (< 10%) and moderate C35/C34 homohopane (< 1) are consistent with the mixed marine–terrigenous dysoxic organic matter input. The oils are assumed to be originated from Early Cretaceous source rocks at the peak of the oil generation window in a kitchen area located to the south of the studied region (i.e., the Binak–Borazjan Trough). The hydrocarbons were migrated from this kitchen to the structurally shallow-seated reservoirs in the center and west of the Kharg-Mish local paleo-high. The Khami Group reservoirs are not effectively sealed by the thin Hith anhydrites, and the Kazhdumi Formation finally trapped the migrated hydrocarbons. This study improves our knowledge regarding one of the active petroleum systems in the South Dezful Embayment, enhancing petroleum exploration success by navigating further drillings into the more prosperous targets.

scholarly journals Timing of oil expulsion from source rocks and a revitalization of the pre-1970 model

2021 ◽  
Author(s):  
Per Arne Bjørkum
Keyword(s):  
Organic Matter ◽  
Source Rock ◽  
Heavy Oil ◽  
Low Temperatures ◽  
Upper Jurassic ◽  
Hydrogen Gas ◽  
Source Rocks ◽  
Co2 Gas ◽  
Chemical Attributes ◽  
Oil Expulsion

New data from North Sea Upper Jurassic source rock samples show no decline in the total amount of organic matter (TOC) within the oil expulsion window between 120 and 150°C which is a key prediction by today’s model for oil expulsion. However, today’s model for oil expulsion is not consistent with either subsurface source rock TOC data or chemical attributes of shallow oils. Instead, these data are more consistent with oil expulsion occurring at much lower temperatures and shallower depths, more similar to models advocated by most oil explorers prior to 1970 where the oil was assumed to have expelled at burial depths less than ~2km. In this paper, main oil expulsion has been determined to be take place at burial depths less than 1km and approximately 30°C. The oil is mobilized by CO2 gas which is generated from decomposing organic matter and is predicted to migrate out of the source rock and into nearby high-permeable rocks via horizontal fractures that originate from loadbearing swelling organic lamina and in a direction towards decreasing overburden. The thermally immature (heavy) oil is then converted to light crude within the reservoir oil starting at 60-70°C by hydrogenation. Hydrogen gas is common in subsurface fluids and is provided to pooled oil from coalification of organic matter in mudstones. Thus, if the supply of hydrogen is limited, in-reservoir thermal upgrading will be hampered. In this model, most of the heavy oil accumulations encountered are immature rather than due to biodegradation of mature oil at low temperatures.

scholarly journals Organic Geochemistry Of The Middle To Upper Jurassic Source Rocks Succession In Balad-1 Well, Balad Oil Field, Central Iraq

2021 ◽  
Vol 71 ◽  
pp. 125-138
Author(s):  
Fawzi M.O. Albeyati ◽  
◽  
Rzger A. Abdula ◽  
Rushdy S. Othman ◽  
Keyword(s):  
Organic Matter ◽  
Organic Geochemistry ◽  
Equilibrium Phase ◽  
Organic Matter Content ◽  
Upper Jurassic ◽  
Matter Content ◽  
Oil Field ◽  
Source Rocks ◽  
Content Type ◽  
Depositional Setting

Thirty four cuttings samples from the Jurassic rock succession in well Balad-1 in the Balad Oil Field, Central Iraq have been collected. Using various organic geochemical techniques, the organic matter’s quantity, quality, maturity, and their source rock’s depositional setting were determined. The samples were evaluated to determine the amount of their organic matter content, type of organic matter, δ13C carbon isotopes abundance for both saturated and aromatic, and molecular properties. The results of organic geochemistry analysis show that Sargelu, Gotnia, and Chia Gara formations contain fair to decent amounts of organic matter. Naokelekan Formation encompasses fair to excellent organic matter, while Najmah Formation comprises very high to exceptional organic matter. The analyzed samples revealed the existence of kerogen types III and II/III mainly within oil window. Thermal maturity related biomarkers are in a good agreement with Rock-Eval parameters, but did not reach equilibrium phase. Source related biomarkers show that these rock units rich in organic matter were mainly deposited in an anoxic marine depositional setting which consists of carbonate influenced by terrestrial input.

scholarly journals Upper Jurassic–Lower Cretaceous Source Rocks in the North of Western Siberia: Comprehensive Geochemical Characterization and Reconstruction of Paleo-Sedimentation Conditions

Geosciences ◽  
2021 ◽  
Vol 11 (8) ◽  
pp. 320
Author(s):  
Evgeniya Leushina ◽  
Timur Bulatov ◽  
Elena Kozlova ◽  
Ivan Panchenko ◽  
Andrey Voropaev ◽  
...  
Keyword(s):  
Organic Matter ◽  
Lower Cretaceous ◽  
Organic Matter Content ◽  
Upper Jurassic ◽  
Matter Content ◽  
Source Rocks ◽  
Organic Carbon Content ◽  
Sea Level Changes ◽  
The North ◽  
Terrigenous Sedimentation

The present work is devoted to geochemical studies of the Bazhenov Formation in the north of the West Siberian Petroleum Basin. The object is the Upper Jurassic–Lower Cretaceous section, characterized by significant variations in total organic carbon content and petroleum generation potential of organic matter at the beginning of the oil window. The manuscript presents the integration of isotopic and geochemical analyses aimed at the evaluation of the genesis of the rocks in the peripheral part of the Bazhenov Sea and reconstruction of paleoenvironments that controlled the accumulation of organic matter in sediments, its composition and diagenetic alterations. According to the obtained data, the sediments were accumulated under marine conditions with a generally moderate and periodically increasing terrigenous influx. The variations in organic matter composition are determined by redox conditions and terrigenous input which correlate with the eustatic sea level changes during transgressive/regressive cycles and activation of currents. Transgression is associated with an intensive accumulation of organic matter under anoxic to euxinic conditions and insignificant influence of terrigenous sources, resulting in the formation of rocks with oil-generating properties. During the regression periods, the terrigenous sedimentation increased along with the dissolved oxygen concentration, and deposits with low organic matter content and gas-generating properties were formed.

scholarly journals Changing depositional environments in the semi-restricted Late Jurassic Lemeš Basin (Outer Dinarides; Croatia)

Facies ◽  
2021 ◽  
Vol 68 (1) ◽  
Author(s):  
Michael A. J. Vitzthum ◽  
Hans-Jürgen Gawlick ◽  
Reinhard F. Sachsenhofer ◽  
Stefan Neumeister
Keyword(s):  
Organic Matter ◽  
Deep Water ◽  
Carbonate Platform ◽  
Upper Jurassic ◽  
Depositional Environments ◽  
Source Rocks ◽  
Terrestrial Organic Matter ◽  
Kerogen Type ◽  
Marine Algal ◽  
Rock Eval

AbstractThe up to 450 m-thick Upper Jurassic Lemeš Formation includes organic-rich deep-water (max. ~ 300 m) sedimentary rocks deposited in the Lemeš Basin within the Adriatic Carbonate Platform (AdCP). The Lemeš Formation was investigated regarding (1) bio- and chemostratigraphy, (2) depositional environment, and (3) source rock potential. A multi-proxy approach—microfacies, Rock–Eval pyrolysis, maceral analysis, biomarkers, and stable isotope ratios—was used. Based on the results, the Lemeš Formation is subdivided from base to top into Lemeš Units 1–3. Deposition of deep-water sediments was related to a late Oxfordian deepening event causing open-marine conditions and accumulation of radiolarian-rich wackestones (Unit 1). Unit 2, which is about 50 m thick and Lower early Kimmeridgian (E. bimammatum to S. platynota, ammonite zones) in age, was deposited in a restricted, strongly oxygen-depleted basin. It consists of radiolarian pack- and grainstones with high amounts of kerogen type II-S organic matter (avg. TOC 3.57 wt.%). Although the biomass is predominantly marine algal and bacterial in origin, minor terrestrial organic matter that was transported from nearby land areas is also present. The overlying Unit 3 records a shallowing of the basin and a return to oxygenated conditions. The evolution of the Lemeš Basin is explained by buckling of the AdCP due to ophiolite obduction and compressional tectonics in the Inner Dinarides. Lemeš Unit 2 contains prolific oil-prone source rocks. Though thermally immature at the study location, these rocks could generate about 1.3 t of hydrocarbon per m2 surface area when mature.

scholarly journals Initiation of petroleum exploration in Jameson Land, East Greenland

1986 ◽  
Vol 128 ◽  
pp. 103-121
Author(s):  
F Surlyk ◽  
S Piasecki ◽  
F Rolle
Keyword(s):  
Lower Triassic ◽  
Scientific Work ◽  
Upper Jurassic ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Upper Permian ◽  
Lower Permian ◽  
Western Basin ◽  
East Greenland ◽  
Promising Source

Active petroleum exploration in East Greenland is of fairly recent date and was preceded by a much longer history of scientific work and mineral exploration. The discovery in 1948 of lead-zinc mineralisation at Mestersvig resulted in the formation of Nordisk Mineselskab AIS in 1952. In the beginning of the seventies Nordisk Mineselskab initiated cooperation with the American oil company Atlantic Richfield (ARCO) in order to undertake petroleum exploration in Jameson Land. The Jameson Land basin contains a very thick Upper Palaeozoic - Mesozoic sedimentary sequence. Important potential source rocks are Lower Permian lacustrine mudstone, Upper Permian black marine mudstone, Middle Triassic dark marine limestone, uppermost Triassic black marginal marine mudstone, Lower Jurassic black mudstone and Upper Jurassic deep shelf black mudstone. Tbe Upper Permian mudstone, which is the most promising source rock, is immature to weakly mature along the western basin margin and is expected to be in the oil or gas-generating zone when deeply buried in the central part of the basin. Potential reservoir rocks include Upper Permian bank and mound limestones, uppermost Permian fan delta sandstones, Lower Triassic aeolian and braided river sandstones, and Lower, Middle and Upper Jurassic sandstones. The most important trap types are expected to be stratigraphic, such as Upper Permian limestone bodies, or combination stratigraphic-structural such as uppermost Permian or Lower Triassic sandstones in Early Triassic tilted fault blocks. In the offshore areas additional play types are probably to be found in tilted Jurassic fault blocks containing thick Lower, Middle and Upper Jurassic sandstones and lowermost Cretaceous sandstones and conglomerates. The recognition of the potential of the Upper Permian in petroleum exploration in East Greenland has important implications for petroleum exploration on the Norwegian shelf.

THE GEOLOGY AND EVOLUTION OF THE SOUTH PEPPER HYDROCARBON ACCUMULATION

1985 ◽  
Vol 25 (1) ◽  
pp. 235 ◽  
Author(s):  
A.F. Williams ◽  
D.J. Poynton
Keyword(s):  
Middle Miocene ◽  
Oil And Gas ◽  
Upper Jurassic ◽  
Lower Jurassic ◽  
Source Rocks ◽  
The South ◽  
Hydrocarbon Migration ◽  
Tectonic Event ◽  
The North ◽  
Migration History

The South Pepper field, discovered in 1982, is located 30 km southwest of Barrow Island in the offshore portion of the Barrow Sub-basin, Western Australia. The oil and gas accumulation occurs in the uppermost sands of the Lower Cretaceous Barrow Group and the overlying low permeability Mardie Greensand Member of the Muderong Shale.The hydrocarbons are trapped in one of several fault closed anticlines which lie on a high trend that includes the North Herald, Pepper and Barrow Island structures. This trend is postulated to have formed during the late Valanginian as the result of differential compaction and drape over a buried submarine fan sequence. During the Turonian the trend acted as a locus for folding induced by right-lateral wrenching along the sub-basin edge. Concurrent normal faulting dissected the fold into a number of smaller anticlines. This essentially compressional tectonic phase contrasted with the earlier extensional regime which was associated with rift development during the Callovian. A compressional tectonic event in the Middle Miocene produced apparent reverse movement on the South Pepper Fault but only minor changes to the structural closure.Geochemical and structural evidence indicates at least two periods of hydrocarbon migration into the top Barrow Group - Mardie Greensand reservoir. The earlier occurred in the Turonian subsequent to the period of wrench tectonics and involved the migration of oil from Lower Jurassic Dingo Claystone source rocks up the South Pepper Fault. This oil was biodegraded before the second episode of migration occurred after the Middle Miocene tectonism. The later oil is believed to have been sourced by the Middle to Upper Jurassic Dingo Claystone. Biodegradation at this stage ceased or became insignificant due to temperature increase and reduction of meteoric water flow. Gas-condensate, sourced from Triassic or Lower Jurassic sediments may have migrated into the structure with this second oil although a more recent migration cannot be ruled out.The proposed structural and hydrocarbon migration history fits regional as well as local geological observations for the Barrow Sub-basin. Further data particularly from older sections of the stratigraphic column within the area are needed to refine the interpretation.

scholarly journals Structural reconstructions of the Eastern Barents Sea at Meso-Tertiary evolution and influence on petroleum potential

Georesursy ◽  
2021 ◽  
Vol 23 (1) ◽  
pp. 78-84
Author(s):  
Anna A. Suslova ◽  
Antonina V. Stoupakova ◽  
Alina V. Mordasova ◽  
Roman S. Sautkin
Keyword(s):  
Barents Sea ◽  
Upper Jurassic ◽  
Lower Jurassic ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Seismic Profiles ◽  
Borehole Data ◽  
Petroleum Potential ◽  
Petroleum Systems ◽  
Novaya Zemlya

Barents Sea basin is the most explored and studied by the regional and petroleum geologists on the Russian Arctic shelf and has approved gas reserves. However, there are many questions in the petroleum exploration, one of them is the structural reconstruction. During its geological evolution, Barents Sea shelf was influenced by the Pre-Novaya Zemlya structural zone that uplifted several times in Mesozoic and Cenozoic. The main goal of the research is to clarify the periods of structural reconstructions of the Eastern Barents shelf and its influence on the petroleum systems of the Barents Sea shelf. A database of regional seismic profiles and offshore borehole data collected over the past decade on the Petroleum Geology Department of the Lomonosov Moscow State University allows to define main unconformities and seismic sequences, to reconstruct the periods of subsidence and uplifts in Mesozoic and Cenozoic. The structural reconstructions on the Eastern Barents Sea in the Triassic-Jurassic boundary led to intensive uplifts and formation of the huge inversion swells, which is expressed in erosional truncation and stratigraphic unconformity in the Upper Triassic and Lower Jurassic strata. In the Jurassic period, tectonic subsidence reigned on the shelf, when the uplifts including the highs of Novaya Zemlya were partially flooded and regional clay seal and source rocks – Upper Jurassic «black clays» – deposited on the shelf. The next contraction phase manifested itself as a second impulse of the growth of inversion swells in the Late Jurassic-Early Cretaceous. Cenozoic uplift of the Pre-Novaya Zemlya structural zone and the entire Barents Sea shelf led to significant erosion of the Mesozoic sediments, on the one hand, forming modern structural traps, and on the other, significantly destroying the Albian, once regional seal.

Oil–source rock correlation for tight oil in tuffaceous reservoirs in the Permian Tiaohu Formation, Santanghu Basin, northwest China

2015 ◽  
Vol 52 (11) ◽  
pp. 1014-1026 ◽  
Author(s):  
Jian Ma ◽  
Zhilong Huang ◽  
Xiaoyu Gao ◽  
Changchao Chen
Keyword(s):  
Organic Matter ◽  
Crude Oil ◽  
Source Rock ◽  
Stable Carbon Isotope ◽  
Northwest China ◽  
Source Rocks ◽  
Tight Oil ◽  
Stable Carbon ◽  
Lucaogou Formation ◽  
Oil Source

Tight oil in the Permian Tiaohu Formation in the Santanghu Basin, northwest China, has a peculiar property such that the reservoir is sedimentary organic matter-bearing tuff characterized by high porosity (10%–25%) and very low permeability, mainly in the range of 0.01–0.50 mD. Biomarker and stable carbon isotope compositions of selected crude oils and source-rock extracts were analyzed to determine the source rock of the tight oil. Source rocks in the Lucaogou Formation consist of various rock types dominated by mudstones containing organic matter with intense yellow–green fluorescence. Mudstones in the Lucaogou Formation have total organic carbon (TOC) values mainly in the range of 1.0–8.0 wt%, hydrocarbon generation potential (S1 + S2) mostly >6 mg/g, and chloroform extractable bitumen “A” generally >0.1%. The maceral composition is predominantly fluorescing amorphinite. The hydrogen index (HI) varies from 300 to 900 mg HC/g TOC, indicating dominant Type I and Type II kerogen. Compared with the mudstones and tuffs in the Tiaohu Formation, the mudstones in the Lucaogou Formation are the best source rocks. The biomarker characteristics of mudstone extracts in the Lucaogou Formation differ from those in the Tiaohu Formation, based on the gammacerane index, β-carotane content, and the relative contents of C27, C28, and C29 regular steranes. Crude oil samples in the tuff show low pristane/phytane (Pr/Ph) ratios, high gammacerane indices, high β-carotane, and a dominance of the C29 regular sterane followed by C28 and C27 steranes, as well as depleted stable carbon isotope compositions. Oil–source correlation with biomarkers and δ13C values shows that the crude oil in the tuffs mainly originates from underlying source rocks in the Lucaogou Formation. The sedimentary organic matter in the tuffs also makes a small contribution to the tuffaceous reservoir. Therefore, the tuffaceous tight reservoir in the Tiaohu Formation is unusual in that the oil is not indigenous; rather, it migrates a long distance to accumulate in the upper reservoir.

scholarly journals Geochemical evaluation of the carbonaceous shale of the upper cretaceous Anambra Basin for potential gas generation, Nigeria

2021 ◽  
Vol 14 (6) ◽  
Author(s):  
George Oluwole Akintola ◽  
Phillips Reuben Ikhane ◽  
Francis Amponsah-Dacosta ◽  
Ayoade Festus Adeagbo ◽  
Sphiwe Emmanuel Mhlongo ◽  
...  
Keyword(s):  
Organic Matter ◽  
Natural Gas ◽  
Source Rocks ◽  
Carbonaceous Shale ◽  
Hydrocarbon Generation ◽  
Petrophysical Parameters ◽  
Type Iii ◽  
Anambra Basin ◽  
Geochemical Evaluation ◽  
Extractable Organic Matter

AbstractThe rise in demand for natural gas has spurred the need to investigate the inland sedimentary basin for more potential sources. In response, the petrophysical parameters of the carbonaceous shale samples from two deep boreholes of Anambra Basin were evaluated. The gas-prone nature of Nkporo shale showed a thermal evolution of a Type III kerogen with initial HI value between 650 and 800 mgHC/gTOC, S2/S3 < 1, a maximum Tmax value of 488°C and have a low hydrocarbon generation potential ranging from 0.07 to 0.15. However, the average TOC content (2.21 wt%) indicated a good source rocks for hydrocarbon since it exceeds threshold limit of 0.5%. The plot of HI against Tmax shows that the organic matter belongs to the Type-III kerogen which reflects the capability of the Npkoro Formation to generate more natural gas than oil compared to Type-II kerogen. The high values (>3) of pristane/phytane ratio in both wells indicated that the organic matter belongs to terrigenous source deposited under anoxic condition which is typical of non-marine shale. The presence of Oleanane content in the Cretaceous shale sediments indicated the contribution of cell wall and woody plant tissues from the terrestrial higher plant. The low concentrations of extractable organic matter (EOM) present in form of isoprenoid and aliphatic hydrocarbon indicated little or no bitumen extract from the studied shale. Considering the high carbon preference indices (CPI) value greater than 1, the preponderance of vitrinite organic macerals and other favourable aforementioned petrophysical parameters, the non-marine Npkoro Shale Basin has significant potential to generate and expel natural gas apart from the current marine basins.

scholarly journals Evaluation of hydrocarbon generation potential of source rock using two-dimensional modeling of sedimentary basin: a case study in North Dezful Embayment, Southwest Iran

2021 ◽  
Author(s):  
Ashkan Maleki ◽  
Mohammad Hossein Saberi ◽  
Seyed Ali Moallemi ◽  
Mohammad Hassan Jazayeri
Keyword(s):  
Organic Matter Content ◽  
Source Rocks ◽  
High Rate ◽  
Hydrocarbon Generation ◽  
Type Ii ◽  
Burial History ◽  
Path Modeling ◽  
Dezful Embayment ◽  
Two Systems ◽  
Kazhdumi Formation

AbstractEarly Cretaceous and Jurassic sequences in the southwestern Iran host some of the largest hydrocarbon reservoirs in the globe. This study is aimed at evaluating the maturity of hydrocarbon fluids, migration paths, and characteristics of Pabdeh, Kazhdumi, Garu and Sargelu source rocks in this region. For this purpose, 27 samples of Pabdeh and Kazhdumi Formations from wells in the northern part of Dezful Embayment were chemically evaluated by Rock–Eval pyrolysis. OpenFlow™ software was utilized to analyze the burial history, conduct 1D thermal modeling in four oilfields and perform 2D modeling on a section to estimate the maturity and extension of sediments. Results of the 1D modeling showed that the kerogens of Sargelu, Garu and Kazhdumi Formations were properly matured, leading to some hydrocarbon outflow, although the organic matter content of Pabdeh Formation was too immature to produce any hydrocarbon. Based on the plot of hydrogen index (HI) versus Tmax, it was found that the studied formations were dominated by type II kerogen and a mixed species of type II and type III kerogens. Results of the migration path modeling showed some leakage from the Kazhdumi Formation up to an overlying seal that prevented the hydrocarbons from seeping out to surface. The Early and Middle Cretaceous oil systems were found to be connected through geometrical features or faults, with the Kazhdumi Formation separating the two systems. The results further showed the migration of hydrocarbons, at a relatively high rate, into the Abadan Plate through the sub-Kazhdumi reservoirs.The Early and Middle Cretaceous petroleum systems were found to be connected through particular geometry features or possibly faults, with the two systems separated by Kazhdumi Formation. For most part, the intensity of the maturation processes was found to decrease from east to west of the study area.

Sign in / Sign up

Export Citation Format

Share Document