Hydrocarbon Migration Research Articles

Basin and petroleum systems modelling to characterise multi-source hydrocarbon generation: A case study on the inner Moray Firth, UK North Sea

In this paper we used basin and petroleum systems modelling (BPSM) of the Inner Moray Firth, UK North Sea to identify the contributions of different source rocks, mixing ratios of accumulated hydrocarbons, and migration pathways of charging the three known fields in the basin – Beatrice, Jacky and Lybster fields. In this study, model scenarios indicate that extensive faulting is a key control on hydrocarbon migration and accumulation, that the accumulations in the basin do not contain Kimmeridge Clay Formation oil, and that they are mixed in a ratio of ∼65:35 Devonian Fish Bed vs Pentland Formation contribution. Migration modelling suggests that Beatrice Field was charged predominantly by proximally sourced hydrocarbons, whereas Jacky and Lybster fields were charged by a near-even mix of proximal and deep-basin hydrocarbons from the Great Glen Sub-Basin.

Multiphase flow behavior of diesel in bog, fen, and swamp peats

Hydrocarbon fate and transport in various categories of peatlands is complicated by the botanical origin, and thus variations in the hydraulic structures and surface chemistry of its peat soils. There has been no systematic evaluation of the role of different peat types on hydrocarbon migration. Thus, two-phase, and three-phase flow experiments were performed for living and partially decomposed peat cores from bog, fen, and swamp peatlands. Numerical simulations of water drainage were performed using HYDRUS-1D, diesel-water and diesel-water-air flow using MATLAB Reservoir Simulation Toolbox (MRST). Five water table (WT) fluctuations were imposed to explore its potential to reduce residual diesel saturation in peat columns. Our results demonstrate a good match of the relative water permeability (krw) – saturation (S) relations estimated using the unsaturated hydraulic conductivity-S relation derived from HYDRUS-1D modeling of two-phase flow, and krw – S from MRST for three-phase flow, for all tested peat columns. Thus, we recommended using two-phase system based krw – S predictions if multiphase data are unavailable for peatland sites' spill management plans. We found the discharge of water and diesel both increase with increasing hydraulic conductivity, while residual water and diesel were within the range of 0.42–0.52 and of 0.04–0.11, respectively. High diesel discharge rates suggest that quick spill-response is required to manage its spread in peatlands. Up to 29% of residual diesel saturation was yielded by the five WT fluctuations, and thus we strongly recommend WT manipulation as a first step towards diesel decontamination progression in peatlands.

A New Methodology Combining Geophysical Calculations and Geological Analysis to Identify and Characterize Carrier Systems for Vertical Hydrocarbon Migration in the Central Diapir Zone of the Yinggehai Basin, China

To understand hydrocarbon migration in terms of the mechanisms, accumulations and exploration targets, it is essential to correctly identify and characterize the carrier systems that control fluid-migration history and oil/gas reservoir formation. The Yinggehai Basin in China is an important area for natural gas exploration and production. However, due to the argillaceous sand sedimentary environment and the absence of faults from the Neogene thermal subsidence period, traditional migration pathways are absent in the Yinggehai Basin, posing significant challenges to target evaluation in this area. Exploration shows that most of the existing gas reservoirs are associated with vertical migration. In this work, coherence cube and curvature seismic techniques are used in the central diapir zone of the Yinggehai Basin to identify diapir-associated fractures and regional stress. Together with geological analysis, two categories of carrier system are discussed in detail to explain the complex migration and accumulation patterns that have puzzled the area. Diapirs have five evolutionary phases, i.e., pressurization, piercing, equilibrium, release and collapse, which have different fracture development patterns, leading to different mechanisms of hydrocarbon migration and accumulation. The carbon isotopes of gaseous hydrocarbons in DF shallow layers and mid-deep layers have an inverted order distribution, indicating mixed accumulation with different maturity, whereas in the mid-deep layers of the diapir-affected areas, there is a single accumulation with low maturity. Early diapiric activity allowed the natural gas produced from deep source rocks to migrate upward along the diapiric carrier system and accumulate in suitable traps to form gas reservoirs. For regional-stress related fractures, the gradual loss of overpressure and fluids from deep to shallow in high-pressure fractures results in the gas accumulation time of deep traps in the regional stress-related carrier system being relatively late and the gas accumulation time of shallow traps being relatively early.

Fluid evolution and petroleum accumulation in the precambrian gas reservoirs of the Sichuan Basin, SW China

Deep marine carbonates comprise one of the most significant reservoir types globally. Reconstruction of Precambrian oil reservoirs and the complex tectonism that affected Precambrian carbonate reservoirs demonstrate the complexity of the natural gas enrichment mechanism. A comparison between the fluid evolution of the well-preserved reservoirs in the central Sichuan Basin and the poorly preserved reservoirs in the southeastern Sichuan Basin offers insights into the factors that control the preservation of ancient reservoirs. We conducted geochemical analysis of the multistage cementation sequence, Raman quantitative analysis on fluid (gas) inclusions, and rare earth element (REE) analysis of diagenetic fluid environments. Hydrocarbon migration can cause variations in the diagenetic environment. Quantitative Raman measurements of the trapping pressure, trapping temperature, and composition of fluid (gas) inclusions are also useful in defining periods of gas accumulation. In situ U–Pb dating results of dolomite veins indicate that extensive dolomitization in the Sichuan Basin began during the early Cambrian. In the central Sichuan Basin, reservoir pressure evolved from normal during the Middle Jurassic to strongly overpressured during the mid-Cretaceous. Overpressure generated before Himalayan tectonism appears to be positively correlated with gas preservation. Overpressure within inclusions bearing hydrogen sulfide indicates that thermochemical sulfate reduction (TSR) does not produce intense dissolution that increases the porosity of carbonate reservoirs and reduces pore pressure. Poorly preserved reservoirs were intruded by exogenous and hydrothermal fluids but remained normally pressured. Secondary methane-rich gas inclusions record normal pressure conditions during the early Paleogene.

Overprinting of δ13Corg signatures in the sedimentary record linked to hydrocarbon migration: Evidence from Paleozoic drill cores from the Ordos Basin, China

Carbon isotopic compositions of organic matter (δ13Corg) provide critical information about changes in the global carbon cycle through Earth's history. However, several biotic and abiotic processes occurring after sediment deposition may overprint the original geochemical signals, complicating their paleoenvironmental interpretation. Here, we report multiple large and rapid δ13Corg swings (ranging from −30.8‰ to −23.3‰) from three Paleozoic drill cores in the Ordos Basin, Northwest China, which may reflect different organic contributions related to lithology. As a potentially important organic matter source, migrated hydrocarbons may substantially alter the original δ13Corg and total organic carbon contents (TOC), and their oxidation may contribute to forming 13C- and 18O-depelted carbonate cements in siliciclastic-dominated strata at depth. Cross-plots of δ13Corg and TOC from samples of the three drill cores all show similar hyperbolic trends that are well simulated using Rayleigh fractionation and a two-component mixing model, thus providing potential criteria for identifying the reservoir and the related hydrocarbon source in oil exploration. Our data call for a critical reassessment of the δ13Corg records of sedimentary rocks if hydrocarbon redistribution or mixing of organic sources is suspected to have occurred during the burial history.

Control of complex lithofacies on the shale oil potential in ancient alkaline lacustrine basins: The Fengcheng Formation, Mahu Sag, Junggar basin

The study of ultra-deep (>4500 m) oil and gas reservoirs in hydrocarbon-bearing basins is a hot spot for oil and gas exploration in the world today, the heterogeneity of lithofacies is a key factor influencing the potential of deep-buried shale oil. It is highly important to better understand the control of complex rock on the shale oil potential for shale oil exploration and development. The Fengcheng Formation (P1f) in the Mahu Sag is a type of ancient alkaline lacustrine shale oil, which was chosen as a research example in this paper. Four lithofacies were identified based on mineralogy: felsic, lime, dolomitic and mixed shale lithofacies. P1f exhibits a very high shale oil potential, and the oil saturation index (OSI) can reach 176 mg HC/g TOC, far exceeding the lower limit of effective benefits. The shale lithofacies of P1f is complex, and the complex lithofacies has a controlling effect on shale oil potential, specifically in terms of hydrocarbon generation, storage and hydrocarbon migration. The different lithofacies differ in various aspects and are controlled by different factors. Felsic shale is an enriched oil shale with a high hydrocarbon generation potential and high storage capacity that can receive foreign hydrocarbons. Mixed shale is a self-generating and self-accumulating oil shale with a low hydrocarbon production potential and low storage capacity. Lime shale is a partial reservoir-type oil shale with a low hydrocarbon production capacity and satisfactory storage capacity that can receive foreign hydrocarbons. Dolomite shale is a partial source rock-type oil shale exhibiting a high hydrocarbon generation capacity and low storage capacity, which can expel hydrocarbons. Studies have indicated that felsic shale exhibits a notable hydrocarbon generation potential, high storage capacity, easy foreign hydrocarbon migration, high brittle mineral content, and easy fracture production. This shale type is the most favorable shale oil exploration target in P1f within the Mahu Sag. In addition, this study reveals the relationship between rock lithofacies and shale oil potential, which provides a new idea for the potential evaluation of similar lacustrine shale oil.

The characteristics of strike-slip faults and their control on hydrocarbon distribution in deep carbonate reservoirs of the central Sichuan Basin

The past decade has witnessed a breakthrough in the gas exploration of deep marine carbonates of the central Sichuan Basin. Deep faults research has also attracted increasing attention, as faulting plays an important role in reservoir control. Previous studies have suggested a developed series of high-angle strike-slip fault systems in the central Sichuan Basin, but correlated exploration activities are limited, as distribution rules and dynamic mechanisms remain unclear. In this study, the spectral decomposition coherence method was used to describe the geometric and kinematic characteristics of these strike-slip faults. Using a comprehensive analysis technique to assess the strike-slip fault tectonic activity history, the formation and evolution processes of strike-slip faults and their control on hydrocarbon distribution were examined. The results showed that the deep strike-slip fault system, mostly distributed in the Dengying Formation, can be divided into four stages, three levels, and three groups of orientation, which controlled the structural framework and shape of the central Sichuan area, as well as the zoning from north to south, and blocking from west to east. The faults showed features of layered deformation and staged evolution in the vertical direction. The segmentation of strike-slip faults strongly controls the quality of fractured vuggy reservoirs. Reservoirs of the hard-linked zone of the strike-slip fault are the most developed, followed by those of soft-linked segments, with translational sections of the strike-slip fault being relatively undeveloped. Strike-slip faults are important hydrocarbon migration paths, and their multistage activities have different controlling effects on hydrocarbon accumulation.

Safety assessment of 'waxes, paraffinic, refined, derived from petroleum-based or synthetic hydrocarbon feedstock, low viscosity' for use in food contact materials.

The EFSA Panelon Food Contact Materials, Enzymes and Processing Aids (CEP Panel) assessed the safety of the 'waxes, paraffinic, refined, derived from petroleum-based or synthetic hydrocarbon feedstock, low viscosity' (FCM No. 93), for which the uses were requested to be extended for articles in contact with fatty foods. Migration from low-density polyethylene samples containing 1% w/w of a representative wax was tested in food simulants. In fatty food simulants, the migration of mineral oil saturated hydrocarbons (MOSH) ≤ C35 was 142mg/kg food, exceeding the overall migration limit for plastic FCM. Mineral oil aromatic hydrocarbons (MOAH) with at least two rings are largely removed during the manufacturing process. Based on various lines of evidence, the Panelconcluded that any concern for the potential presence of MOAH with two or more conjugated aromatic rings can be ruled out. Based on the genotoxicity studies and on the content of polycyclic aromatic hydrocarbons (PAHs), the substance does not raise a concern for genotoxicity. Available toxicokinetic data showed a limited accumulation of MOSH. No adverse effects were observed up to the highest tested dose of 9g/kg body weight per day in a 90-day repeated oral toxicity study in Sprague-Dawley rats. The available results showed that FCM No. 93 is devoid of endocrine activity. The provided information on chronic toxicity and carcinogenicity was limited and inadequate to reach conclusions on these endpoints. Therefore, the CEP Panelconcluded that under the intended and tested conditions of uses, the substance does not raise safety concern for the consumer if used to a level ensuring that its migration into food is no more than 5mg/kg.

The Lower Silurian (Hot Shale) Source Rocks of Western Iraq: Depositional Model and Stratigraphic Distribution

The Hoseiba Member, an Early Silurian basal mature hot shale of the Akkas Formation (Silurian) consists of about 80% of the Paleozoic hydrocarbon potential system, it is organic-rich with total organic carbon up to 16% as the main source for the Paleozoic gas resources in Iraq. The hot shale is the main source of rocks that are penetrated in deep wells in the western Iraqi desert such as Akkas-1, Qaim-1, and Khleisia -1, which are distributed due to paleo uplift in the restricted regional basin in the west, south, and northwest Iraqi desert and wedged to north thrust zone in Ora area of extreme northern Iraq, Ora subbasin to Aljezira NW and in the west where the approved source rocks of ‘Hot shale” Akkas -Widyian subbasin (Rephrase). The Hoseiba Member, basal hot shale in the Akkas Formation in Iraq and their correlative units are extended within neighboring countries Jordan, Syria, Saudi Arabia, Iran, Oman, and south Turkey. Qualitative and quantity of Hot Shales source rocks Silurian are Excellent in Akkas well -1 (0.95-16.62%) TOC in Akk-1 Akkas sub-basin west Iraq and an average thickness (30 m.) with 1-9.94% TOC in Kh-1 Al-Jezira sub-basin NW Iraq. The hot shale distribution was controlled by the Caledonian uplift that created paleo-high in northern Iraq and moderately deep to the northwest, and deep depression deposition in west and south desert Iraq. The hot shale expulsion and migration of hydrocarbon are controlled by the underlying main reservoir of the Khabour Formation K1 sandstone ember by block faulting

Vertically transferred overpressures along faults in Mesozoic reservoirs in the central Junggar Basin, northwestern China: Implications for hydrocarbon accumulation and preservation

Abnormally high pressure (overpressure) is common in oil reservoirs of the Mesozoic formations in the central Junggar Basin. However, the generation mechanisms of overpressure are still uncertain, which not only affects safe drilling implementation, but also restricts the understanding of hydrocarbon migration and accumulation. Based on measured pressures and mud weights, the pore pressure distributions in the Mesozoic formations are characterized in detail. The different generation mechanisms of overpressure in mudstones and sandstones are investigated based on logging responses and basin modeling. Finally, the significance of reservoir overpressure to oil accumulation and leakage is discussed. The results indicate that overpressure in the Mesozoic reservoirs in the central Junggar Basin is mainly developed below 4500 m, the excess pressures are between 12 and 58 MPa, the pressure gradient ranges from 12 to 21 MPa/km, the pressure ratios range from 0.6 to 0.95, and the overpressure ratios are between 0.25 and 0.91. The high-overpressure in reservoirs is mostly present in isolated sand bodies that are hydraulically connected to Permian source rocks by faults. The overpressure data corresponding to a pressure gradient of 11–14 MPa/km plot on the loading curve, showing typical disequilibrium compaction overpressure. The points with pressure gradients greater than 14 MPa/km obviously deviate from the loading curve, indicating unloading overpressure mechanisms. The logging responses and numerical simulation results confirm that the overpressure in mudstone is mainly generated by disequilibrium compaction and chemical compaction, and hydrocarbon generation has a limited contribution. The unloading overpressure in the sandstone is mainly generated by the vertical overpressure transfer process from the deep Permian overpressured compartment. The vertical transfer of overpressure is often related to oil migration and accompanied by high oil saturations. However, high-overpressure presents challenges for the sealing capacity of caprocks. Hydrofracturing or the activation of preexisting faults due to high overpressure determines the risk of seal failure, which controls hydrocarbon leakage. The research is of great significance for understanding the mechanisms of hydrocarbon migration along faults and evaluating caprock integrity in similar basins.

Characteristics and source analysis of polycyclic aromatic hydrocarbons in organisms and manure near Ardley Island, Antarctica

In order to better understand the migration and accumulation behavior of polycyclic aromatic hydrocarbons (PAHs) in biological chains in the cold environment around the Ardley Island, a variety of biological and penguin manure samples during China's 36th Antarctic Scientific expedition have been collected and studied. A certain difference in PAHs concentration was observed in the environmental samples, and the order of size was as follows: fish > limpets > krill > manure > brown alga > mosses. The percentage of PAHs with different ring numbers in brown alga, moss, and krill was in the following order: three rings > two rings > four rings > five rings > six rings. The proportion of HMW-PAHs in limpets and fish samples was higher than that in brown alga, moss, manure, and krill samples. The main source of PAHs in environmental samples near Ardley Island is oil, which may be due to the development of tourism in Antarctica, the number of ships and human activities around the region. Therefore, it is imperative to strengthen the protection of the ecological environment in the area around Ardley Island.

Characterization of ultra-deeply buried middle Triassic Leikoupo marine carbonate petroleum system (!) in the Western Sichuan depression, China

Ultra-deeply buried (>5000 m) marine carbonate reservoirs have gradually become important exploration targets. This research focuses on providing an understanding of the basic elements of the ultra-deeply buried Middle Triassic Leikoupo marine carbonate petroleum system within the Western Sichuan Depression, China. Comprehensive analyses of organic geochemistry, natural gas, and C–H–He–Ne–Ar isotope compositions suggest that the reservoir is charged with compound gases from four source rock units including the Permian Longtan, Middle Triassic Leikoupo, Late Triassic Maantang and Xiaotangzi formations. Approximately a 50-m thick outcrop and 100-m length of drilling cores were examined in detail, and 108 samples were collected from six different exploration wells in order to conduct petrographic and petrophysical analyses. Thin-section and scanning electron microscope (SEM) observations, helium porosity and permeability measurements, mercury injection capillary pressure (MICP) analysis, and wire-line logging (5500–6900 m) indicate that the reservoir lithologies include argillaceous algal limestones, dolograinstones, crystalline dolostones, and microbially-derived stromatolitic and thrombolitic dolostones. Reservoir properties exhibit extreme heterogeneity due to different paleogeographic environmental controls and mutual interactions between constructive (e.g., epigenetic paleo-karstification, burial dissolution, structural movement, pressure-solution and dolomitization) and destructive (e.g., physical/chemical compaction, cementation, infilling, recrystallization, and replacement) diagenetic processes. An unconformity-related epigenetic karstification zone was identified in the uppermost fourth member of the Leikoupo Formation, which has developed secondary solution-enhanced pores, vugs, and holes that resulted in higher porosity (1.8–14.2%) and permeability (0.2–7.7 mD). The homogeneity and tightness of the reservoir increases with depth below the unconformity, and it is characterized by primary intergranular and intracrystalline pores, solution pores, fractures, stylolites, and micropores with a lower helium porosity (0.6–4.1%) and permeability (0.003–125.2 mD). Regional seals consist of the Late Triassic Xujiahe Formation, comprised of ∼300 m of mudstones that are overlain by ∼5000-m thick of Jurassic to Quaternary continental argillaceous overburden rocks. Effective traps are dominated by a combination of structural-stratigraphic types. Paleo-reservoir crude oil cracking, wet-gases, and dry-gases from three successive hydrocarbon generation processes supplied the sufficient hydrocarbon resources. The homogenization temperatures of the hydrocarbon-associated aqueous fluid inclusions range from 98 to 130 °C and 130–171 °C, which suggests hydrocarbon charging occurred between 220–170 Ma and 130–90 Ma, respectively. One-dimensional basin evolution models combined with structural geologic and seismic profiles across wells PZ1-XQS1-CK1-XCS1-TS1 show that hydrocarbon migration and entrapment mainly occurred via the unconformity and interconnected fault-fracture networks with migration and charging driven by formation overpressure, abnormal fluid flow pressure, and buoyancy forces during the Indosinian and Yanshanian orogenies, with experiencing additional transformation occurring during the Himalayan orogeny. The predicted estimated reserves reached ∼300 × 109 m3. The results provide excellent scientific implications for similar sedimentary basin studies, it is believed that abundant analogous deeply buried marine carbonate hydrocarbon resources yet to be discovered in China and elsewhere worldwide in the near future.

The Curie depths of the United Arab Emirates: Implications for regional thermal structures and tectonic terranes

We have determined the depth of the Curie isotherm in the United Arab Emirates (UAE) using a modified centroid method based on the fractal distribution of sources. The derived spatial coverage of Curie depths and geothermal gradients are consistent with the geothermal gradients derived from the bottom hole temperatures measured in exploration wells and reveal three NNE–SSW to NE–SW-trending regions of shallow Curie depths. These are: (1) the north-western offshore region of the UAE with Curie depths of 11–25 km; (2) in central UAE ranging from the Shah field in south-central regions of the UAE to the northern offshore region of Dubai, with Curie depths of 10–25 km, high geothermal gradients of 22.1–55.3 °C/km, and high heat flows of 55.3–138.3 mW/m2; and (3) in the eastern region of the UAE from Al Ain to Dibba and the Gulf of Oman, with medium Curie depths of 25–30 km. These regions of shallow Curie depths are flanked by two NS to NE–SW-trending regions of deeper Curie depths between 35 and 50 km with low geothermal gradients and heat flows of 11.1–15.8 °C/km and 27.8–39.5 mW/m2 respectively. We interpreted these regional NE–SW trends to be related to tectonic terranes composed of magmatic arcs and microcontinental fragments that have amalgamated to form the crust beneath the UAE. In addition, many large hydrocarbon fields are located immediately above or on the margins of these shallow Curie depth zones, suggesting that the shallow Curie depth could have played a critical role in the maturation, migration, and entrapment of hydrocarbons in the UAE. Furthermore, since these zones delineate areas of high heat flow (>100 mW/m2) and high geothermal gradients (∼40 °C/km) they represent areas in which future geothermal exploration could be focused.

Origin of Mesozoic Biodegraded Crude Oils from the Eastern Chepaizi Uplift (Junggar Basin) Constrained by the Biomarker Recovery Method

The Mesozoic (Jurassic and Cretaceous) sandstone reservoirs in the eastern Chepaizi Uplift of the Junggar Basin (NW China) have become hot targets in recent years for their substantial amounts of oils discovered. However, the oil origin has been a controversial issue due to biodegradation. In this study, hierarchical cluster analysis and principal component analysis show that the Mesozoic crude oils can be divided into three oil families (A1, A2, and A3). Meanwhile, the biodegradation level of the three oil families (PM 6 to 9+) was evaluated based on the PM scale and the parameter-stripping method of strongly resistant parameters. Allowing for this extremely high biodegradation case, this study adopted a biomarker recovery method to recover the original appearances of the three oil families. Here, eight parameters related to hopane (H), tricyclic terpane (TT), and C24-tetracyclic terpane (C24 Tet) were recovered, the dispersion of eight parameter sets is significantly reduced, and the geochemical characteristics are more obvious, especially for TT. Thus, this reliability and robustness, as well as the similarity between the source rock and the biodegraded crude oils, encourage us to perform oil–source correlation. The oil–source correlation revealed that family A1 was derived from the Permian source rocks in the Shawan Sag, family A2 was mainly derived from the Permian source rocks in the Shawan Sag and mixed with a small amount of oils generated by the Jurassic source rocks in the Sikeshu Sag and the Carboniferous source rocks in the Chepaizi Uplift, and family A3 mainly originated from the Permian source rocks in the Shawan Sag mixed with a small amount of oil produced by the Carboniferous source rocks in the Chepaizi Uplift. This conclusion is also further supported by effective biomarker parameters and a stable carbon isotope (δ13C), discriminant analysis, hydrocarbon migration, and restored paleogeomorphology. The parameter recovery is evidenced as one of the most useful methods and showed higher resolution than the conventional oil–source correlation to identify the origins of biodegraded oils.

Reservoir properties and hydrocarbon enrichment law of Chang 1 oil layer group in Yanchang Formation, Wanhua area, Ordos Basin

Evaluation of tight oil reservoir properties is of great significance to the exploration of oil and gas in tight reservoirs. The Chang 1 Member of the Yanchang Formation in the Wanhua Area, Ordos Basin is a new exploration stratum for tight sandstone oil. The lack of understanding of reservoir characteristics and crude oil enrichment rules has seriously restricted the efficient development of oil and gas resources in this stratum. In this study, the reservoir characteristics of the Chang 1 Member in the Wanhua area and the effects of superimposed sand bodies, structures and paleogeomorphology on accumulation of hydrocarbons were systematically studied. The Chang 1 sandstone is a typical ultra-low porosity-ultra-low permeability reservoir, and it has experienced destructive diagenesis of mechanical compaction, pressure solution and cementation, and constructive diagenesis of dissolution. Strong pressure solution caused the secondary enlargement of quartz and feldspar and the formation of patchy dense mosaic structures. The target layer has experienced argillaceous, siliceous and carbonate cementations. Moreover, the sandstone reservoir in the Chang 1 Member also experienced strong dissolution, and it is the main factor for the formation of secondary pores and the improvement of reservoir physical properties. The study also found that the main types of pores in the Chang 1 Member are intergranular dissolved pores and remaining intergranular pores. Superimposed sand bodies, nose-shaped uplifts, dominant facies and eroded paleo-highlands have significant effects on the hydrocarbon accumulation. Based on this study, it was found that the migration and accumulation mode of hydrocarbons in the Chang 1 reservoir belongs to the ladder-like climbing migration + structural ridge accumulation type. In addition, sand body thickness is an important controlling factor for the hydrocarbon accumulation. At present, the discovered crude oil in the Chang 1 Member is always distributed in the areas with thick sand bodies (>20 m), and most of the sand bodies have a thickness in the range of 25–40 m, and the effective thickness is in the range of 2–6 m. In addition, the eroded highlands are the highest topographic units, they are favorable areas for the large-scale accumulation of oil and gas.

Evolution of the hydrocarbon migration system of the lower enping formation in the pearl river estuary basin

The Enping Formation of the Paleogene System in the Lufeng south area of the Pearl River Estuary Basin has good potential for hydrocarbon exploration. It is characterized by a vertically large distribution of a crude oil type and a widely horizontal distribution of similar crude oil. With the complex characteristics of hydrocarbon distribution and migration, studying the evolution mode of this migration system on a dynamic scale is necessary. In this study, the key accumulation period was determined using existing logging, seismic, and microscopic data combined with fluid inclusion and burial history. Then, the system's migration path and the direction of migration in the key accumulation period were analyzed, and the migration system and evolution model in the study area were established. The results show two stages of accumulation in the southern Lufeng area: 19–8 Ma and 8–0 Ma. In the first stage, the reservoir mainly followed the transport of a far-source fault–sand–ridge coupling system and the traps on the migration path were favorable for hydrocarbon accumulation. In the second accumulation period, traps that developed near the oil-source faults were favorable for hydrocarbon accumulation. The favorable traps in the first accumulation period were distributed in the whole area. The traps in the southwest wells B921 and C1211 were larger than the first stage, whereas the favorable traps in the northeast and central parts were mainly distributed in B211D and its adjacent well area, with smaller and scattered traps. Favorable traps in the second accumulation period were mainly distributed in the eastern and central regions, around wells B211D and B161, whereas the traps in the southwest were not conducive to hydrocarbon accumulation due to the lack of effective transport system connection. The results of this study have a certain guiding significance for practical exploration.

Key stage and model of hydrocarbon accumulation of Ordovician reservoir in Gucheng area, Tarim Basin, China

The heterogeneity of deep carbonate reservoirs is strong, it is significant for exploration and development to clarify the key stages of oil and gas accumulation. Taking the Ordovician in the Gucheng area of Tarim Basin as an example, this paper systematically investigated the key stage and model of hydrocarbon accumulation using the data of the cores, thin sections, cathode luminescence tests, laser ablation U-Pb isotope geochronometry, bitumen reflectance, and fluid inclusion tests, and seismic interpretation. (1) The Tarim Basin mainly develops three sets of effective source rocks, namely the Cambrian Yuertusi Formation, Cambrian Moheershan Formation, and Mid-Lower Ordovician Heituwa Formation, which are concentrated in the slope-basin facies of eastern Tarim Basin. (2) The Gucheng area is located in a favorable paleo-structural position. The pathway system composed of vertical faults and lateral unconformities occurs in the paleo-uplift, which is critical for hydrocarbon migration and accumulation. (3) The laser in-situ U-Pb dating, distribution and genesis of reservoir bitumen, burial-thermal maturation history, and the homogenization temperature of fluid inclusions suggest that the multi-stage tectonic thermal events of the Caledonian and Hercynian stages result in key adjustment and modification to deep hydrocarbon accumulation. Due to magmatic hydrothermal activities, the Caledonian primary oil reservoir massively evolved into oil-cracking gas reservoirs and residual paleo-oil reservoirs. (4) The paleo tectonic-fluid effect plays an important factor controlling the development of the Ordovician reservoirs. The evolution of the hydrocarbon accumulation in Gucheng area can be divided into three stages, namely formation of primary oil and gas reservoirs, oil-cracking gas reservoirs, and adjustment, destruction and reforming of gas reservoirs. To sum up, the western and northern parts of the paleo-uplift with favorable source-reservoir-cap rock assemblage and less effects of hydrothermal activities are the favorable zones for hydrocarbon exploration in the Gucheng area, the Tarim Basin.

Investigation of the Gravity Anomalies within Brass and Environs, Niger Delta Area, Nigeria: Implications for Hydrocarbon Prospectivity

The airborne gravity data over Brass Area and environs, Niger Delta Area, Nigeria were processed and interpreted in order to delineate the sedimentary thickness within the basin and map out places with the potentials for hydrocarbon formation, accumulation and migration. The geological structures, depths andstructural trends within the area were investigated using Total Horizontal Gradient, Tilt Derivative, Analytical Signal Filters and Euler Deconvolution techniques. The results from Euler depths showed that the sedimentary thickness and structural depths within the area range from about 1.6 to over 17.4 km.The area predominantly has NE-SW structural trend with minor NW-SE trend.The sediment thickness and structural endowment of the area prompted the classification of Egeregere, Brass, Spiff Town, Kirikakiri Areas in the northern and the southern partsof the area as zones of very viable potentials for hydrocarbon generation, accumulation and migration.

RESERVOIR CHARACTERIZATION OF THE ‘SHULA FIELD’, OFFSHORE NIGER DELTA BASIN, NIGERIA: AN INTEGRATED APPROACH

This study analyzed “Shula field” offshore Niger Delta basin for it hydrocarbon bearing capacity. Well logs and seismic data were used for the analysis. Well logs consisting of gamma ray, resistivity, neutron and density logs for five different wells were used. Gamma ray logs aided lithological identification, resistivity logs were used to delineate hydrocarbon bearing zones while a combination of neutron and density logs aided in distinguishing oil and gas zones. Three hydrocarbon bearing sands (reservoirs) of varying thickness designated as RES-AA, RES-BB and RES-CC were identified. Well log correlation of the five wells revealed lateral continuity of the sand units thinning out in northwestern direction of the study field. The range values of gross thickness (GT), net-to-gross (NTG), volume of shale (VSH), effective porosity (ΦEff), permeability (K), hydrocarbon saturation (Sh) and water saturation (SW) for RES-AA reservoir are 51-74ft, 0.88-98%, 0.10-11%, 24-28%, 174-734mD, 8-80%, and 20-92% respectively. RES-BB reservoir range values of (GT), (NTG), (VSH), (ΦEff), (K), (Sh) and (SW) are 47-65ft, 83-98%, 8-14%, 24-32%, 234-1880mD, 4-78%, and 22-96% respectively while the RES-CC reservoir range values of (GT), (NTG), (VSH), (ΦEff), (K), (Sh) and (SW) are 121-191ft, 82-96%, 8-11%, 23-31%, 125-1352mD, 9-88% and 12-91% respectively. Sixteen faults were identified and interpreted comprising of nine synthetic and seven antithetic faults. The time and depth structural maps show the subsurface structural geometry and possible hydrocarbon migration and trapping potential. The probable structure trapping hydrocarbon in the study field is anticlinal structure and four-way closure. The volumetric calculation revealed that reservoir RES-AA has 951 × 106 bbl, reservoir RES-BB has 1058 × 106 bbl and reservoir RES-CC has 1688 × 106 bbl of oil originally in place (OIIP). Generally, the petrophysical results and the volumetric calculation for the field confirm an economically viable investment potential except for reservoir RES-AA, wellbore ZY-005 with 8% Sh, reservoir RES-BB, wellbore ZY-003 and ZY-005 with 4% Sh, and 7% Sh respectively and reservoir RES-CC, wellbore ZY-005 with 9% Sh. Therefore, these four reservoir units may be screen out during production to reduce the rate of water cut thereby increasing the producing life of the field.

«Палеозойская» нефть Урманского месторождения (юго-восток Западной Сибири)

This paper presents the results of applying paleotemperature modelling for determination possible sources, which form hydrocarbon deposits in the pre-Jurassic basement in the southeast of Western Siberia. Discovery of light oil deposits below the depth of 7000 m in the Tarim basin indicates the possibility of existence favourable temperature regime for generation and conservation of hydrocarbon deposits even at such great depths. According to some estimates about 40 % of the total proved oil and gas reserves in the world are distributed in the superdeep strata. Russian scientists also have extensive prospects for the Paleozoic sedimentary basins of Western Siberian Plate. These basins formed on betwixt mountains, where favourable environment for accumulation of dispersed organic matter and its transformation into hydrocarbons persisted for a long geological time. There are two concepts of “the main source” for oil accumulated in the Paleozoic reservoirs. The first suggests deposit formation via upward migration, while the second supports the idea of downward interstratal migration of hydrocarbons from the Jurassic source rocks. The aim of this study is to determine possible sources for the Paleozoic hydrocarbon deposits in the Urman field via modelling of thermal history of the Phanerozoic oil-source rocks. The first experience of performing such research is related to the Ostanino group of fields. The research is continued for the Chuzic-Chizhapka group of fields, which is located on the tectonic unit of the same name. Both groups are associated with the Nyurol sedimentary basin. It was found that the Paleozoic reservoir of the Urman field accumulates partially preserved gas generated by the Paleozoic source-rocks and oil representing a mixture of the Jurassic oil of marine and terrigenous origin.