Hydrocarbon Expulsion Research Articles

Porous aluminosilicates catalysts for low and medium matured shale oil in situ upgrading

AbstractFor medium and low matured shale oil exploration, in situ upgrading could promote the oil recovery. There are two main disadvantages herein, high exploration temperature and large energy consumption. The new approach has been proposed to apply porous aluminosilicate catalysts for shale oil highly efficient upgrading at 350°C, H‐clin and Ni‐clin catalysts were prepared with natural clinoptilolite. Al‐SBA‐15 catalysts were synthesized by following one‐step crystallization procedure, and firstly employed for shale oil in situ upgrading. Kinetic studies of pyrolysis showed that the activation energy of organic matter conversion in shale was reduced from 113.80 kJ mol−1 to 37.28 kJ mol−1. After the catalyst addition, shale oil conversion temperature was declined, the reaction rate was increased, and the energy consumption of in situ upgrading was reduced. In Sinopec patented testing instrument, hydrocarbon generation and hydrocarbon expulsion unit, shale oil catalytic conversion showed increased hydrocarbon generation by 2%‐16%. Under the same reaction conditions, the Al‐SBA‐15 (Si/Al = 5) revealed the best activity for hydrocarbon generation, and the efficiency was elevated to 32.67%, twice as that of thermal conversion. The quality of catalytically produced oil was promoted, by improving the further cracking of bitumen to light oil and gas. The results have a breakthrough significance for intensifying the high‐efficiency hydrocarbon generation and expulsion process of low and medium matured shale oil.

Quality, hydrocarbon generation, and expulsion of the Eocene Enping Formation source rocks in the Wenchang Depression, western Pearl River Mouth Basin, South China Sea

Recently, increasing numbers of oil and gas reservoirs have been discovered in the Wenchang Depression, western Pearl River Mouth Basin, South China Sea, revealing prospects for hydrocarbon exploration. The Enping Formation (E3e) is a key target layer for the development of source rocks. However, previous work has only focused on lacustrine swamp source rocks of E3e in the Wenchang A Sag, without a systematic study of shallow lacustrine source rocks. In this study, the quality of E3e shallow lacustrine source rocks is reevaluated, and the hydrocarbon generation and expulsion characteristics are analyzed using relevant geological data and constructing a conceptual model. The results show that the E3e2 source rocks have greater thickness (50–600 m) and similar organic matter abundance (0.5–2.5%) compared with the E3e1 source rocks (50–500 m and 0.5–2.5%). On the whole, the E3e source rocks were deposited in the continental environment and are dominated by Type II and Type III kerogen. Meanwhile, the E3e source rocks of the Wenchang A Sag are in the stage of mature to over mature, while those of the Wenchang B Sag are in the stage of low mature. Vertically, the hydrocarbon generation potential of the E3e2 source rocks is greater than E3e1. Also, the cumulative hydrocarbon production of steep slope in the Wenchang A Sag is larger than that in the Wenchang B Sag. In addition, the corresponding vitrinite reflectances of hydrocarbon expulsion threshold and peak are 0.72 and 0.96%, respectively. Horizontally, four hydrocarbon generation and expulsion centers were mainly concentrated in different subsags of the Wenchang A and B Sags for E3e. The maximum values of hydrocarbon generation and expulsion intensity for E3e1 are 1500 × 104 t/km2 and 1000 × 104 t/km2, respectively, while those for E3e2 are 1800 × 104 t/km2 and 1200 × 104 t/km2, respectively, with the expulsion efficiency of 75%.

Unconformity-controlled dissolution contributes to reservoirs in the carbonate-rich Permian Fengcheng Formation, northwestern Junggar Basin, China

The Permian Fengcheng Formation is a set of complex sedimentary strata in the Mahu Sag, northwestern Junggar Basin, where various types of carbonate minerals occur. Coarse crystalline calcite assemblages and other carbonate minerals, such as dolomite, shortite and sodium carbonates, are also common in the Fengcheng Formation. Their dissolution by meteoric freshwater leaching at tectonic high positions, which was controlled by an unconformity, developed uncommonly high-quality secondary porosity and contributed to unconventional oil and gas exploration. Based on core analyses, thin section studies under optical and cathodoluminescence (CL) microscopes, geological interpretations of seismic profiles, and carbon and oxygen isotope composition analyses from coarse crystalline calcite assemblages and comparisons to other carbonate minerals, this study focuses on the origin of coarse crystalline calcite assemblages and the mechanism of unconformity-related dissolution to form hydrocarbon reservoir spaces. Coarse crystalline calcite assemblages are the products of multiple stages of recrystallization of other carbonate minerals in nearby host rocks. Hydrolysis of feldspar and volcanic sediments provided additional Ca2+ for calcite precipitation. The dissolution and reprecipitation of carbonate minerals were associated with organic maturation and hydrocarbon expulsion and migration. The crystallization process was slow, which allowed the crystal assemblages to grow to large sizes. Organic carbon was involved in the formation of the coarse crystalline calcite assemblages, which resulted in much more negative carbon isotope compositions than those of other carbonate minerals via diluting the carbon isotope compositions of preexisting carbonate minerals. Later tectonic uplift caused a regional unconformity and formed dissolution reservoirs in tectonically high positions. Furthermore, faults and fractures provided paths for the solutes to transfer to lower positions and reprecipitate when they became saturated.

The chemical kinetics of the semi-open hydrous pyrolysis system: Time series analysis of lithostatic pressure and fluid pressure

As a problem that has plagued geochemists, the perspective of time has long been recognized as an important factor in organic matter evolution and hydrocarbon generation. This article discusses two time series analysis methods based on econometrics, damping trend and autoregressive integrated moving average (ARIMA), to mine the potential value of data and abstract useful information from pyrolysis experiments. The case studies use marine source rocks (depth of 3119–3230 m, in the LH29–2 well) from the Enping Formation in the Baiyun Sag, the deep-water area (depth of >300 m) of the northern South China Sea, which has a geological background of high temperature, high pressure and rapid burial in the late stage. A tubular plug flow microreactor is used to artificially mature the source rock in the laboratory, and the conditions of hydrous pyrolysis are listed as follows: temperatures of 250°C, 300°C, 350°C, 400°C, 450°C, and 500°C; lithostatic pressure of 33~89 MPa; fluid pressure of 16~38 MPa; and time duration of 72 h. The results revealed that as the degree of maturation increased (Ro from 0.27 to 2.04), the cumulative yield of hydrocarbon gas increased rapidly (max = 311.64 ml/g⋅TOC), the yield of the expelled oil increased first and then decreased (peak = 350.69 mg/g⋅TOC at 350°C), and the yield of residual oil extracted from residue decreased gradually. Although the kinetic parameters of kerogen can be calculated by conventional pyrolysis experiments, the long-term cumulative effect of episodic-hydrocarbon expulsion in real conditions is often neglected. The major contributions of our statistical approach for geological applications are described as follows: (1) the recognition of qualitative changes within hydrocarbon generation and expulsion; (2) the characterization of episodic-hydrocarbon expulsion that describes the evolution of the lithostatic pressure and fluid pressure; (3) the disclosure of new influencing factors abstracted from time series models to describe the frequency distribution of hydrocarbon expulsion; and (4) an evaluation of the dependency of new variables.

Generation and expulsion process of the Chang 7 oil shale in the Ordos Basin based on temperature-based semi-open pyrolysis: Implications for in-situ conversion process

There is a substantial amount of oil shale resources in the seventh member of the Triassic Yanchang Formation (abbreviated as Chang 7) in the Ordos Basin, and its geological and geochemical characteristics are highly suitable for in-situ conversion process (ICP). A comprehensive characterization of its hydrocarbon generation, expulsion and retention features will help determine the optimum conditions for future field tests. However, typical thermal simulation experiments based on either open-system or closed-system are not applicable to provide data to construct the models. Therefore, in this study, eight parallel thermal simulation experiments, which were based on the newly designed temperature-based semi-open pyrolysis experiments were performed on the Chang 7 oil shale. The yields (including cumulative yields and net incremental yields) and compositional characteristics of the expelled oil, expelled gas, and retained oil were analyzed. Results show that the hydrocarbon expulsion has a coupling relationship with hydrocarbon generation that can be divided into four stages: (1) Slow hydrocarbon generation stage (300–320 °C, 0.53–0.55 %Ro). Minimal amounts of oil and gas are generated in this stage. The hydrocarbon expulsion efficiency increases rapidly. (2) Quick oil-generation stage (320–380 °C, 0.55–1.09 %Ro). The fast cracking of kerogen and thermal bitumen generates a large amount of oil. The hydrocarbon expulsion efficiency remains relatively stable. (3) The secondary oil cracking and quick gas-generation stage (380–420 °C, 1.09–1.66 %Ro). The oil yield begins to decrease after reaching its maximum and a large amount of hydrocarbon gas is generated. The oil generation capability of kerogen is basically exhausted. The hydrocarbon expulsion efficiency and gas/oil ratio increase rapidly at this stage. (4) The heavy hydrocarbon gas cracking stage (after 420 °C, 1.66 %Ro). The oil yield continues to decline, accompanied by the onset decline in the gas yield (except methane). At this time, the hydrocarbon expulsion efficiency continues to increase but at a rather low speed. Under the experimental conditions in this study, 1.24–1.66% Ro is considered a favorable thermal maturity interval, in which maximum oil production with relatively light components can be obtained and the hydrocarbon gas is abundant.

Experimental study of the influences of pressure on generation and expulsion of hydrocarbons: A case study from mudstone source rocks and its geological application in the Tarim Basin

Generally, pressure, temperature, depth of organic matter/kerogen burial and organic and inorganic matter interactions can influence the hydrocarbon generation process. However, different understandings were proposed to interpret the role of pressure in hydrocarbon generation. Meanwhile, previous investigations of the influence of pressure on hydrocarbons generation are mainly focused on fluid pressure (FP), only a few work was involved in the effect of lithostatic stress (LS) due to the limitation of experimental techniques. In this study, simulation experiments were conducted to investigate the influence of pressure, including lithostatic stress (LS) and fluid pressure (FP) on yield and process of hydrocarbon generation by a modified simulation instrument. Two systematic comparative pyrolysis experiments, including pressured experiments with LP range from 27.6 to 179.4 MPa and FP range from 12.0 to 109.2 MPa, and non-pressured experiments with LP for 6.0 MPa and FP range from 2.0 to 5.0 MPa were conducted in hydrous experimental condition. The results show that the peak yields of the expelled oil and the liquid hydrocarbons in pressured experiments and non-pressured experiments are 42.48 mg/g·TOC, 52.00 mg/g·TOC, 70.14 mg/g·TOC, and 72.15 mg/g·TOC, respectively. And Ro, ratio of the expelled oil to eluted oil, the accumulated yield of the expelled oil and liquid hydrocarbons, are lower in pressured experiments than that of non-pressured experiments. However, the accumulated yields of eluted oil and residual oil are higher in pressured experiments than that of non-pressured experiments. Additionally, the expulsion efficiencies of the oil range from 20% to 25%, which are lower in pressured experiments than that of non-pressured experiments near the oil generation-window. In addition, the yields of hydrocarbon gas in pressured experiments are greater compared to the yields in non-pressured experiments at the high maturity stage. Based on the experimental results, hydrocarbon generation process can be divided into three stages. Generally, LS and FP could retard the process of mudstone maturation as well as the generation and expulsion of the liquid hydrocarbons. Hence, the residual liquid hydrocarbons in high-pressure condition can act as another source of natural gas generation in the high maturity stage. The results could help us to properly evaluate hydrocarbon generation potentials of sources rocks at petroleum-producing sedimentary basins in China and elsewhere.

Mud volcanoes and the presence of PAHs

A mud volcano (MV) is a naturally hydrocarbon-spiked environment, as indicated by the presence of various quantities of PAHs and aromatic isotopic shifts in its sediments. Recurrent expulsion of various hydrocarbons consolidates the growth of hydrocarbonoclastic bacterial communities in the areas around MVs. In addition to the widely-known availability of biologically malleable alkanes, MVs can represent hotbeds of polyaromatic hydrocarbons (PAHs), as well - an aspect that has not been previously explored. This study measured the availability of highly recalcitrant PAHs and the isotopic signature of MV sediments both by GC-MS and δ13C analyses. Subsequently, this study highlighted both the occurrence and distribution of putative PAH-degrading bacterial OTUs using a metabarcoding technique. The putative hydrocarbonoclastic taxa incidence are the following: Enterobacteriaceae (31.5%), Methylobacteriaceae (19.9%), Bradyrhizobiaceae (16.9%), Oxalobacteraceae (10.2%), Comamonadaceae (7.6%) and Sphingomonadaceae (5.5%). Cumulatively, the results of this study indicate that MVs represent polyaromatic hydrocarbonoclastic hotbeds, as defined by both natural PAH input and high incidence of putative PAH-degrading bacterial OTUs.

Organofacies composition of Upper Jurassic – lowermost Cretaceous source rocks, Danish Central Graben, and insight into the correlation to oils in the Valdemar Field

Abstract The organic-rich marine shales of the Upper Jurassic - lowermost Cretaceous Farsund Formation are the main hydrocarbon source rocks for the Cretaceous chalk reservoir of the Valdemar Field (Danish North Sea). Geochemical analyses of oil extracts from core samples across the greater Valdemar Field show substantial heterogeneity of the reservoir oils, suggesting contribution from kitchen areas with source rocks of variable organofacies and thermal maturity. In order to better understand the source rock facies that charged the field, a refined organofacies characterization of the Upper Jurassic - lowermost Cretaceous marine shale source rock succession (Farsund Formation) in the Danish Central Graben was established. This organofacies characterization is based on integration of petrographic and geochemical data and demonstrates large variations in both the regional and local distribution of the organofacies at the sequence level in the shales within the Danish Central Graben. In addition, the organofacies characterization shows that the respective sequences in the succession may be represented by several organofacies at the same time. Part of the explanation to the heterogeneity in the oil types accumulated within the Valdemar Field may lie in the presence of different organofacies within the uppermost sequences (Vol-3 to Ryaz-1) in the three kitchen areas. Each organofacies presumable generates different types of oils and the variation in the relative proportions of the different organofacies likely determines the composition of the generated oils. One dimensional (1-D) maturity modelling at three pseudo-well locations, each representing a potential Farsund Formation kitchen, shows that all kitchens are in the main oil window and that mainly oil was expelled from the Volg-3 to Ryaz-1 sequences. Modelling indicates that (i) average values of TOC, HI, thickness and the kinetic model are the main controls on generation and expulsion of hydrocarbons; and (ii) by increasing these parameters, expulsion could also occur from the lower part of the succession.

Geochemical characteristics and hydrocarbon expulsion of source rocks in the first member of the Qingshankou Formation in the Qijia‐Gulong Sag, Songliao Basin, Northeast China: Evaluation of shale oil resource potential

AbstractIn recent years, there has been significant progress in shale oil exploration in the first member of the Qingshankou Formation (K2qn1) in the Qijia‐Gulong Sag, Songliao Basin, Northeast China: It shows good prospects for shale oil. However, the recognized lack of the geochemical and hydrocarbon generation and expulsion characteristics of K2qn1 source rocks limits an accurate evaluation of shale oil resource. This study systematically investigated the geological and geochemical characteristics, hydrocarbon generation and expulsion, and shale oil potential of the K2qn1 source rocks. The results show that the K2qn1 mudstones were mainly deposited in the semideep and deep lacustrine facies under reducing and weak reducing conditions. Compared with the southern Gulong Sag, the northern Qijia Sag has a higher salinity, more abundant prosperous aquatic organisms, and a greater paleoproductivity. The K2qn1 source rocks are pervasive and continuous in the entire sag, with maximum thicknesses greater than 110 m. They have a higher organic matter (OM) abundance (2.40% of the average TOC), are dominated by type I and II1 kerogen, and are mature (0.8%‐0.1.3% VR), which indicate that they are good to excellent source rocks and have significant hydrocarbon generation potential. The source rocks in the Qijia Sag have a higher OM abundance, a better OM type, and a lower OM maturity than those in the Gulong Sag. The threshold and peak hydrocarbon expulsion values for marlstone source rocks are 0.85% VR and 0.95% VR, respectively. The volumes of hydrocarbons generated and expulsed from the K2qn1 source rocks are 121.8 × 108 t and 46.9 × 108 t, respectively, with a retention efficiency of 61.5%. The in‐place and recoverable resources of shale oil are 74.9 × 108 t and (12.0‐13.5) × 108 t, respectively, indicating that the entire sag has a significant shale oil potential, especially the Qijia Sag.

Comprehensive basin-wide 3D petroleum systems modelling providing new insights into proven petroleum systems and remaining prospectivity in the Exmouth Sub-basin, Australia

The Exmouth Sub-basin is part of the Northern Carnarvon Basin, offshore north-west Australia, and has undergone a complex tectonic history. Hydrocarbon exploration resulted in the discovery of a variety of oil and gas accumulations; however, their distribution and charge history from different petroleum systems is still poorly understood due to limited knowledge of the deeper basin architecture. The basin-wide, long-offset, broadband 2017 Exmouth 3D multiclient seismic dataset allowed a seamless interpretation into this deeper section. This work revealed new insights on the tectono-stratigraphic evolution of the Exmouth Sub-basin. Mesozoic extension, that was restricted to the latest Triassic, was followed by a sag phase with homogeneous, shale-dominated deposition, resulting in source rock potential for the entire Jurassic section. These findings, together with potential field modelling, were integrated into this first basin-wide 3D petroleum system model to better constrain the thermal history and petroleum systems. The model improved our understanding of the complex charge history of hydrocarbon fields. It predicts that hydrocarbon expulsion from Late Jurassic source rocks continued into the Late Cretaceous, a period when the regional Early Cretaceous Muderong Formation was an efficient seal rock. This implies that, in addition to long-distance, sub-Muderong migration, vertical, short-distance migration may have contributed significant petroleum charge to the discovered accumulations in the southern Exmouth Sub-basin. The model also predicts additional prospective areas: fault-seal structures within Early Cretaceous intervals north of the Novara Arch, intra-formational Late Jurassic sandstones north of the current fields (with low biodegradation risk) and Triassic reservoirs along the basin margins and north of the Jurassic depocentre.

Hydrocarbon generation and expulsion features of the Upper Triassic Xujiahe Formation source rocks and their controlling effects on hydrocarbon accumulation in the Sichuan Basin, Central China

Understanding the features of the hydrocarbon generation and expulsion of the Upper Triassic Xujiahe Formation (T3x) source rocks is important to properly guide petroleum exploration in the Xujiahe Formation in the Sichuan Basin. Based on mass balance, the hydrocarbon generation and expulsion from the T3x source rocks are characterized in this paper through a method (i.e., hydrocarbon generation potential index using pyrolysis data) different from that used in previous studies. The threshold and peak of hydrocarbon expulsion are determined to be Ro = 0.9% and 1.15%, respectively. The amounts of hydrocarbon generated and expelled in the T3x source rocks are 4,525.5 × 108 and 2,420.5 × 108 t, respectively. Moreover, three hydrocarbon expulsion regions T3x have been identified in the Sichuan Basin. On the basis of the hydrocarbon generation and expulsion features of the source rocks and the distribution of the oil‐and‐gas reservoirs, the quantitative model of the hydrocarbon accumulation probability under the control of the T3x source rock is established via single‐factor regression analysis. The predictions obtained through this analysis show that the favourable oil‐and‐gas exploration areas in the Xujiahe Formation are distributed in the Qionglai, Chengdu, and Deyang regions, as well as in the west of Yilong region. Further, the results show that 78% of the discovered oil‐and‐gas reservoirs are located in the predicted favourable and relatively favourable oil‐and‐gas exploration areas.

Geochemical Characteristics and Hydrocarbon Expulsion of Lacustrine Marlstones in the Shulu Sag, Bohai Bay Basin, Eastern China: Assessment of Tight Oil Resources

In recent years, tight oil exploration has made significant progress in the lower part of Shahejie Formation ( $$ {\text{Es}}_{3} ^{{\text{L}}} $$ ) in the Shulu Sag, Bohai Bay Basin, Eastern China, which shows good exploration prospects for tight oil. However, accurate evaluation of tight oil resource potential is influenced by a lack of studies and an incomplete understanding of hydrocarbon expulsion from marlstone source rocks. This study investigated the geological and geochemical characteristics of marlstone source rocks, their hydrocarbon generation and expulsion, and the tight oil resource. Results show that the marlstone source rocks were deposited in a reducing to weakly oxidizing lacustrine environment with low-middle salinity, distributed widely in the central and southern troughs, with the maximum thickness greater than 700 m. The marlstone source rocks have relatively high organic matter abundance (0.06–7.97% of total organic carbon content with an average value of 1.51%), are dominated by type II and I kerogen, and are at the immature to mature stage (0.3% < vitrinite reflectance (VR) < 0.8%), which reveals fair–good source rocks for the marlstones. The threshold and peak of hydrocarbon expulsion for marlstone source rocks are at 0.51% VR and 0.6% VR, respectively. The amounts of generation and expulsion from marlstone source rocks are 19.72 × 108 t and 8.53 × 108 t, respectively, with an expulsion efficiency of 43%. The total tight oil resource in place is 10.9 × 108 (5.8 × 108 t within the carbonate rudstone reservoir and 5.1 × 108 t within the marlstone reservoir), indicating a significant tight oil potential and promising exploration prospect in the Shulu Sag, Bohai Bay Basin, Eastern China.

An improved hydrocarbon generation potential method for quantifying hydrocarbon generation and expulsion characteristics with application example of Paleogene Shahejie Formation, Nanpu Sag, Bohai Bay Basin

Abstract To evaluate petroleum resources, it is important to quantify the hydrocarbon generation and expulsion characteristics of source rock. The hydrocarbon generation potential method is an efficient model for calculating the characteristics of source rocks and evaluating the resource potential. The previous hydrocarbon generation potential model was mainly established by measured Rock-Eval pyrolysis data, and due to inappropriate preservation measures, an important component (volatile hydrocarbon content) of source rock may be significantly reduced. Prior methods may, therefore, not objectively reflect the properties of a source rock and cause unacceptable errors in the resource assessment. This study proposes an improved hydrocarbon generation potential method. The new method considers the initial hydrogen index (HI0) and transformation ratio (Tr) during the evolution of source rocks, which can more realistically reflect the hydrocarbon generation and expulsion history of source rocks. Therefore, the hydrocarbon evaporative loss (Qloss) is calibrated and the hydrocarbon generation and expulsion features of source rocks are more accurately evaluated. The proposed method is used to examine the effectiveness of the third member of the Upper Paleogene Shahejie Formation (Es3) in Nanpu Sag. By utilizing the improved hydrocarbon generation potential model, the hydrocarbon expulsion threshold of the Es3 source rock is positioned at Ro = 0.875%. The maximum hydrocarbon generation and expulsion potential (Qg and Qe) are 593.78 and 323.78 mg HC/g TOC, respectively, and the maximum hydrocarbon expulsion efficiency is 54%. The maximum hydrocarbon generation and expulsion intensities are 500 × 104 t/km2 and 250 × 104 t/km2, respectively, which locate source rock at the Laoyemiao and Gaoshangpu Structural Belts. The amounts of generated and expelled hydrocarbon are 13.7 × 108 t and 6.9 × 108 t, respectively, and the resource potential of the tight oil of the Es3 in the Nanpu Sag is 0.69 × 104 t. Compared with the previous method, the improved hydrocarbon generation potential method limits the maximum Qg and calibrates the Qloss; therefore, the new method more objectively reflects the hydrocarbon generation and expulsion characteristics and resource prospect of the source rock.

Source rock evaluation of subsurface Devonian–Carboniferous succession based on palyno-organic facies analysis in Faghur Basin, North Western Desert of Egypt: a division of the North Africa Paleozoic Basins

The Paleozoic rocks in North Africa are prolific with source rocks that contribute petroleum to giant fields especially in Algeria and Libya. The coeval subsurface source rocks from the Devonian and Carboniferous in the Western Desert of Egypt have been evaluated in the present study. The rocks from Zeitoun, Desouqy, and Dhiffah formations have been evaluated based on integration of the palynofacies, organic geochemical analysis, and well logging. The study depends on samples from five wells that are Buchis-1X, Phiops-1X, Siwa-D-1X, Tayim West-1X, and WKAL C-1XST. The distribution of palynofacies categories are statistically investigated by the principal component analysis (PCA) that specified the proximal-distal environmental trends by the values of component 1 that attributed to the terrestrial organic sources. The analyses revealed mostly poor, fair to good organic enrichments and poor to fair source potential in the studied rocks. The samples are mostly thermally mature, uncontaminated, and of gas prone type III and mixed oil/gas prone type II/III kerogen. The geological conditions that lead to the large difference in the hydrocarbon source potentiality between western North Africa and source rocks evaluated in this study from Egypt have been discussed. It is suggested that these differences resulted from the larger thickness of Paleozoic rocks and the increase in burial depths of the depocenters in the western side that lead to higher maturity levels that are responsible for the organic conversions and hydrocarbon expulsion.

Study of hydrocarbon generation and 1D-2D modeling of hydrocarbon migration at the Karanj and Parsi oilfields, Southern Dezful Embayment, SW Iran

Abstract This study is a 2D basin modeling to determine the petroleum system (i.e. Cretaceous-Neogene play) of the Karanj and Parsi oilfields in the Southern Dezful Embayment, SW Iran. This system is characterized by occurrence of source rocks of Middle Cretaceous, Late Cretaceous and Paleocene to Eocene (Kazhdumi, Pabdeh and Gurpi Formation), reservoirs of Upper Cretaceous and Late Oligocene–Early Miocene (Ilam-Sarvak and Asmari formations), and seals of Paleocene and Miocene (Pabdeh and Gachsaran Formation). Considering temperature, transformation ratio and vitrinite reflectance, the maturity of source rocks (Kazhdumi, Pabdeh and Gurpi Formation) was investigated. A maturity history analysis showed that the maturity of Kazhdumi, Pabdeh and Gurpi Formation started during 70–60 and 4 Ma, respectively. Generation and expulsion of hydrocarbons started ~16 Ma in the Kazhdumi Formation and ~3 Ma in the Pabdeh Formation that continued up to the present. The analysis of the transformation ratio indicates transformation of significant amounts of Kazhdumi source rocks for generating hydrocarbons. Migration of hydrocarbons from the Kazhdumi Formation is mainly vertically upward. From Pabdeh Formation migration is both vertically upward (to the Asmari reservoir) and downwards (to the Ilam-Sarvak reservoir). However, some local traps have formed due to the hydrocarbon accumulation above the faults. Our results reveal that petroleum generation, migration and entrapment occurred at proper timing which facilitated the migration of hydrocarbons and their accumulation in the reservoirs.

The role of Late Cretaceous wrench tectonics in hydrocarbon endowment in El-Gindi Basin, northern Western Desert, Egypt

Abstract Detailed subsurface mapping and structural analysis of El-Gindi basin indicate the hydrocarbon potentiality of the Cretaceous reservoirs. El-Gindi basin is a Late Cretaceous-Eocene basin located at El-Fayium district, northeastern Western Desert of Egypt. The overwhelming impact of the Late Cretaceous wrench tectonics was evident during the inversion of the Jurassic-Early Cretaceous rift-related basins along the North Western Desert of Egypt and subsequent deposition of a thick succession of Eocene sediments (~6000 ft Apollonia Formation) within El-Gindi Basin. These tectonic events were developing the oil maturity and trapping through the Late Cretaceous reservoir sequences, Upper Bahariya Formation (Cenomanian) and the Abu Roash “G” Member (Turonian). The Gindi Fault, however, is a NW-trending basement feature breaching El-Gindi basin and bounding several deeper half grabens in the western half of El-Fayium district. It has been reactivated during the Cretaceous, Eocene and probably Oligocene-Early Miocene times, where extended northwestward to the Qarun Field at the footslopes of the Kattaniya inverted basin forming several oil traps along its strike. The Late Cretaceous dextral wrenching developed a regional system of ENE-oriented structural ridges such as Kattaniya and Silah (bounded El-Gindi basin to the north and south, respectively), associated with a series of NE-to ENE- oriented right-lateral strike-slip faults enclosing some structural closures in between. The development of such ridges causing regional subsidence and subsequent deposition of the Apollonia Formation creating several structural hydrocarbon traps. In addition, the structural closures formed between the ends of right-lateral strike-slip faults at Silah High became potential sites for hydrocarbon accumulation. The thermal maturity model of El-Gindi basin suggests a phase of hydrocarbon expulsion occurred during or immediately after deposition of the Apollonia Formation, where the Lower and Upper Cretaceous sediments passing the oil window. According to the analysis of well cores, E-logs and seismic data, shallow marine to deltaic environments have been assigned for the Cenomanian-Turonian reservoir sediments. Moreover, the deposition within channels, point-bars and estuarine environments for the hydrocarbon bearing sandstone reservoirs within El-Gindi Basin was identified.

Possible new method to discriminate effective source rocks in petroliferous basins: A case study in the Tazhong area, Tarim Basin

Sediments with organic matter content (total organic carbon) TOC ≤ 0.5% which can act as effective source rocks are critical and challenging in the field of petroleum geology. A new method is proposed through a case study to identify and evaluate the effective source rocks, which is applied to study the changing characteristic of hydrocarbon-generation potential index with depth. The burial depth corresponding to the beginning of hydrocarbon-generation potential index reduction represents the hydrocarbon expulsion threshold in source rocks. Then, new identification standards are established for discrimination of effective source rocks of Middle–Upper Ordovician in Tarim Basin. The critical value of TOC for effective source rocks change with their burial depth: the TOC &gt; 0.5% with source rock depth &gt; 4000 m, TOC &gt; 0.4% with depth &gt;4500 m, TOC &gt; 0.3% with depth &gt; 5000 m, TOC &gt; 0.2% with depth &gt;5500 m. Based on the new criteria, effective source rocks in the Middle–Upper Ordovician are identified and their total potential hydrocarbon resources is evaluated, reaches 0.68 × 109 t in the Tazhong area, which is 65.4% higher than that of previous studies and consistent with the exploration result. Thus, this new method is of significance to resource evaluation and can be applied in the carbonate source rocks and mudstone source rocks with high degree of exploration.

One North Sea fairway analysis: revealing opportunities through data integration across scales

Abstract While the North Sea has many well-established prolific plays, the downwards trend of annual discovered resources has cast doubt on the continued ability of the stratigraphy to provide world-class future discoveries. However, despite this downwards trend, significant discoveries can still be made, such as Johan Sverdrup (Norwegian North Sea in 2010). Furthermore, new sub-plays within this petroleum system and new unproven plays with alternative source rocks are still being tested, although often with associated higher perceived pre-drill subsurface risk (Pg) and/or lower volume potential. There is room for new optimism, however, as new approaches and technologies are deployed, which could lead to future success. The analysis of regionally extensive integrated datasets allows for the interpretation of ‘One North Sea’ fairway maps that honour detailed observations from the prospect scale through to the play scale and beyond. By integrating source-rock maturity, hydrocarbon expulsion and migration, well shows, seismically defined gas chimneys, and direct hydrocarbon indications onto regional fairway maps, hydrocarbons can be traced from the source kitchens to the traps. By utilizing a zoom-in/zoom-out methodology, models can be developed, tested and applied across the basin, allowing new ideas to emerge, de-risk established prospects and reveal under-appreciated hydrocarbon volumetric upsides.

Reservoir characteristics and multi-stage hydrocarbon accumulation of the Upper Triassic Yanchang Formation in the southwestern Ordos Basin, NW China

The Chang-8 and Chang-6 members of the Upper Triassic Yanchang Formation (lower part) are regarded as the main oil producing members of the Ordos Basin. Recently, new hydrocarbon discoveries have been made in the upper part of the Yanchang Formation (e.g., Chang-3) in the southwestern Ordos Basin, implying that this interval also has a good potential for hydrocarbon exploration. However, studies on the origin of the high-quality reservoir, hydrocarbon migration, and accumulation patterns remain insufficient. In this study, integrated petrological, mineralogical, and fluid inclusion tests are employed to evaluate reservoir characteristics, and reconstruct the history of hydrocarbon migration and accumulation during oil and gas reservoir formation. The results reveal that the Yanchang Formation is characterized by low porosity (8 − 14%), medium permeability (0.5 − 5 mD), and strong heterogeneity; the reservoir properties are controlled by secondary porosity. Two types of dissolution are recognized in the present study. Secondary pore formation in the lower part of the formation is related to organic acid activity, while dissolution in the upper part is mainly influenced by atmospheric fresh water associated with the unconformity surface. The Yanchang Formation underwent hydrocarbon charging in three phases: the early Early Cretaceous, late Early Cretaceous, and middle Late Cretaceous. A model for hydrocarbon migration and accumulation in the Yanchang reservoirs was established based on the basin evolution. We suggest that hydrocarbon accumulation occurred at the early stage, and that hydrocarbons migrated into the upper part of the Yanchang Formation by way of tectonic fractures and overpressure caused by continuous and episodic hydrocarbon expulsion during secondary migration, forming potential oil reservoirs during the later stage.

Structural evolution of JG and JD fields, Abu Gharadig basin, Western Desert, Egypt, and its impact on hydrocarbon exploration

The Abu Gharadig basin in the Western Desert (NW Egypt) is a mature hydrocarbon province with over 95% of the oil and gas fields in the Upper Cretaceous reservoirs. JG and JD fields are producing fields; JG is producing from the Jurassic reservoirs, while the JD field is producing from the shallower Tertiary reservoir. Both fields lie on the footwall of the main bounding fault of Abu Gharadig basin trending E–W and NW–SE. Four dry wells have been drilled into the deeper Jurassic reservoir, and this paper will try to figure out the possible reasons for the failure of Jurassic reservoir in JD compared to JG field 2002. Two main geological cross sections have been created. The first cross section ties the JD field to the Abu Gharadig basin and the second one ties the JG field to same depocenter. The restoration has been carried out using 2D Move (Midland Valley software) to restore the two sections to their original tectonic status. Since the Eocene–Miocene is the common time for the hydrocarbon expulsion in Abu Gharadig basin, both JG and JD traps were formed at that time. The restoration clearly showed the juxtaposition of the Jurassic reservoirs against Abu Roash and Khoman (shale, limestone and chalk) in JG. In contrary, the Jurassic reservoir is juxtaposed with Kharita and Alam El Bueb (Sandstone) in JD. Fault juxtaposition has been carried out also and concluded the juxtaposition of Abu Roash F member and Masajid flip East of JD well so no chance of Abu Roash F member charging JD.