Burial History Analysis Research Articles

Integrated analysis of source rock evaluation and basin modelling in the Abu Gharadig Basin, Western Desert, Egypt: Insights from pyrolysis data, burial history, and trap characteristics

Source rock evaluation and basin modelling play crucial roles in understanding hydrocarbon potential. In this study, pyrolysis data from 92 shale ditch samples were employed to assess the source rocks in the Abu Gharadig Basin (Western Desert, Egypt). The organic richness ranged from 0.53% to 4.1% by weight, indicating varying hydrocarbon‐generating capabilities. Specifically, kerogen types II and III exhibited the potential to generate hydrocarbons, ranging from fair to good oil sources. The burial history analysis provided insights into the sedimentation and subsidence rates during different geological periods. The Late Jurassic‐Early Cretaceous period witnessed modest rates of sedimentation and subsidence. In contrast, the Oligocene and Late Miocene periods experienced medium burial rates, while the Late Cretaceous‐Early Tertiary period exhibited high burial rates. Specific formations were examined in detail, with the Apollonia Formation standing out as a significant hydrocarbon reservoir. It entered the early oil window at approximately 17.87 Ma and the wet gas window at about 17.41 Ma in the ASSIL‐1X well. However, it didn't reach the GPAA‐4 well. The Abu Roash ‘D’ member also showed promise, entering the early oil window at 38.20 and 47.38 Ma, and the wet gas window at 37.40 and 43.64 Ma. Similarly, the Abu Roash ‘F’ member exhibited favourable hydrocarbon generation, entering the early oil window at 39.90 and 54.86 Ma, and the wet gas window at 39.70 and 51.62 Ma in both the ASSIL‐1X and GPAA‐4 wells. Based on the analysis, the Apollonia, Abu Roash ‘D’ and ‘F’ members were identified as source rocks, while the Kharita, ‘C’, ‘E’ and ‘G’ members were recognized as reservoir rocks. The Abu Roash Shale acted as an effective seal rock. The geological structure of the region revealed the presence of NW‐SE normal faults, forming a three‐way dip closure trap. This research substantially enhances our comprehension of the hydrocarbon system within this basin. It achieves this by thoroughly investigating source rock evaluation, basin modelling and delivering invaluable insights into the mechanisms that govern hydrocarbon generation, expulsion and trap age.

Tectonic movements of the Yanshan-Himalayan period in the northern Longmenshan and their impact on tight gas accumulation of the Shaximiao formation in the Qiulin structure, China

The Jurassic strata constitute a focal area for recent exploration and development of tight gas reservoirs in the western Sichuan Basin. This study investigates the Jurassic Shaximiao Formation in the northern Longmenshan in the Western Sichuan basin, focusing on tight gas reservoirs. The research integrates core and outcrop observations, seismic interpretations, and burial history analyses to understand hydrocarbon source rocks, sedimentation, reservoir characteristics, and structural characteristics. The impact of Yanshan-Himalayan tectonic movements on tight gas reservoir accumulation in the Shaximiao Formation is dissected, primarily around the Qiulin structure. The Western Sichuan Depression basin’s formation is influenced by gravitational gliding tectonics, which can be classified into the ‘Three Zones and One Belt,’ with Longmenshan in the frontal belt. Burial history analysis reveals distinct processes in the foreland belt and the depression basin. In the Qiulin area, gas reservoirs in the Shaximiao Formation are mainly charged by source rocks from the Xujiahe Formation. Tectonic movements play a significant role in creating favorable reservoirs and conditions for hydrocarbon migration and preservation. Natural gas accumulation is primarily controlled by fault connectivity to hydrocarbon sources and effective reservoir thickness. Gravitational sliding tectonics have shaped a fluvial-lacustrine environment for the Shaximiao Formation, with fluvial sand bodies acting as favorable reservoir zones. Small-scale normal faults formed by tectonic movements serve as conduits for natural gas migration. The research findings are of significant guidance for the exploration and development of tight oil and gas resources in western Sichuan basin.

Geochemical properties, mechanism of formation, and source of solid bitumen in the Ediacaran Dengying Formation from the central to northern Sichuan Basin, China

Several large gas reservoirs, including the Weiyuan and Anyue gas fields, have been discovered in the Ediacaran Dengying Formation in the Sichuan Basin, indicating vast opportunities for deep-petroleum exploration. Understanding the origin and evolution process of these gas reservoirs is crucial for further petroleum exploration and development. Although the burial history of the Sichuan Basin and its surrounding areas is basically dominated by Paleozoic burial and preservation, and Meso-Cenozoic uplift and erosion. However, the source of the Dengying Formation natural gas in the Sichuan Basin is still a subject of controversy between the Ediacaran and Cambrian source rocks due to high thermal maturity, secondary alteration, and multistage tectonic activities. This study aims to examine the investigation on the properties and genetics of Dengying solid bitumens that existed in the central to northern Sichuan Basin, in order to provide insights into the source and evolution history of the Dengying paleo-oil reservoirs. For this purpose, petrologic, elemental, and organic geochemical analyses were used to investigate the properties, origin, and formation mechanism of solid bitumens. The results indicate that these solid bitumens have suffered intense thermal alteration (EqVRo 2.1%–5.3%), and are classified as pyrobitumens. Solid bitumens in the Gaoshiti bulge and the north slope area were subjected to tectonic thermal events (e.g., Emeishan igneous province) and relatively strong thermochemical sulfate reduction (TSR) alteration. These solid bitumens were assumed to be pyrolysis products of light (condensate) oil. In contrast, solid bitumens in the Weiyuan bulge and the Micangshan uplift area were not influenced by tectonic thermal events but experienced weak TSR alteration, and originated from either normal or heavy crude oil. Moreover, a systematic bitumen-source correlation was carried out using δ13Corg values, bound steranes, and trace element distributions. Results reveal that the solid bitumens in the central Sichuan paleo-uplift were mainly derived from the lower Cambrian Maidiping Formation, those in the north slope area originated from the lower Cambrian Qiongzhusi Formation, while those in the Micangshan area were sourced from the Ediacaran Doushantuo Formation. Structural and burial history analysis implies that the differences in the source of the Dengying paleo-oil reservoir (i.e., solid bitumen) between these study areas are attributed to the distribution of source rocks and their contact relationship with reservoirs. This research successfully obtained insights into the source and genetic mechanism of paleo-oil reservoirs by analyzing the properties of high-maturity solid bitumens, which can guide further exploration and development of deep petroleum resources.

Inclusion Characteristics of the Fracture-Cave Calcite of Ordovician Yingshan Formation and Its Indication to the Formation of Paleokarst Reservoir in the Northern Slope of Tarim Basin Center Area, China

A karst fracture-cavity was developed in the Ordovician Yingshan Formation in the northern slope of the Tarim Basin center area (Tazhong area); however, the area experienced multistage karst and diagenesis in the later period, and the reservoir was heavily reformed, characterized by complex distribution. Based on the testing of the inclusions in the karst fractures and fracture-cave calcite, this study summarizes the physical and chemical characteristics of the inclusions in the northern slope of Tazhong. The major inclusions were liquid and gas–liquid phases, while the minor ones were hydrocarbon phases. Based on the salinity–homogenization temperature diagram, the gas–liquid inclusions could be divided into seven types: low-temperature low-salinity inclusions (the lowest salinity was 0.88%, which is lower than that of present sea water; the lowest temperature of the inclusions was 49°C); low-temperature high-salinity inclusions; medium-temperature low-salinity inclusions; medium-temperature medium-salinity inclusions; medium-temperature high-salinity inclusions; high-temperature medium-salinity inclusions; and high-temperature high-salinity inclusions. The development of inclusions was characterized by high temperature and high salinity or low temperature and low salinity. In addition, the low-temperature and low-salinity inclusions near the unconformity surface were well-developed. The high-temperature and higher-salinity inclusions far from the unconformity surface were also well-developed. A burial history analysis showed three stages of karstification or filling in the area: exposed karstification in the Middle Caledonian, shallow burial filling in the Middle Hercynian, and burial filling in the Late Hercynian. By determining the inclusions in calcite associated with mud in the karst caves and combined with previous studies, the Middle Caledonian was found to be the period associated with the eogenetic karstification of meteoric water and seawater. This is the key factor in the formation of karst reservoirs in the Tazhong area. The large-scale calcite growth in the Middle Hercynian and Late Hercynian burial periods led to further filling of the early karst reservoir, reduced reservoir space, and enhanced reservoir heterogeneity.

Oil sources and accumulation processes of the Neoproterozoic Luotuoling Formation reservoirs (∼930 Ma) in North China Craton

Oil sources and accumulation processes of the Neoproterozoic Luotuoling Formation (∼930 Ma) in the Liaoxi Depression are investigated using integrated fluid inclusion, basin modelling and oil-source rock correlation analyses. In the upper Luotuoling Formation sandstone reservoir in Han-1 well, abundant bitumen inclusions and white fluorescent bitumen-bearing oil inclusions were observed. Combined with microthermometry of aqueous inclusions and burial history analysis, the oil charge time of the upper Luotuoling Formation sandstone reservoir took place at approximately 465–455 Ma. This oil was derived from the Gaoyuzhuang Formation source rock according to biomarkers and isotope compositions. However, oil generation of the Gaoyuzhuang Formation had already ended before 455 Ma, so the oils cannot be generated directly from the Gaoyuzhuang Formation source rocks, but definitely migrated from the destroyed paleo-oil accumulations in the Wumishan or Tieling formations. In addition, the lower Luotuoling Formation sandstone reservoir contains mainly yellowish orange fluorescent oil inclusions. The oil in the lower Luotuoling Formation sandstone reservoir was directly generated from the Hongshuizhuang source rock at 240–230 Ma. The study on oil accumulation history of the Neoproterozoic Luotuoling Formation reservoir is significant for further exploration of Proterozoic petroleum resources in the Liaoxi Depression, North China Craton.

Densification and Fracture Type of Desert in Tight Oil Reservoirs: A Case Study of the Fuyu Tight Oil Reservoir in the Sanzhao Depression, Songliao Basin

Abstract The exploration of unconventional oil and gas, especially the exploration process of tight oil, is closely related to the evolution of tight reservoirs and the accumulation process. In order to investigate the densification and accumulation process of the Fuyu tight oil reservoir in the Sanzhao depression, Songliao Basin, through the new understanding of reservoir petrological characteristics, diagenesis and diagenetic sequence are combined with a large number of inclusions: temperature measurement, spectral energy measurement, and single-well burial history analysis, and then contrastive analysis with current reservoir conditions. The results prove that diagenesis is dominated by compaction and cementation, and the restoration of paleoporosity shows that its porosity reduction rate reached 67% and the densification process started in the early Nenjiang Formation and was finalized at the end of the Nenjiang Formation. The accumulation of the Fuyu oil layer generally has the characteristics of two stages and multiple episodes, and the main accumulation period is the end of the Mingshui Formation. The end of the Nenjiang Formation, where the main body of the reservoir is densified, is just a prelude to the massive expulsion of hydrocarbons in the Songliao Basin, which makes the Fuyu oil layer have the characteristics of first compacting and then accumulating. Through the above analysis, it can be seen that the accumulation of oil and gas in the Fuyu oil layer, Sanzhao depression, is more dependent on the fault-dominated transport system. In addition, it is believed that tight oil accumulation should have the characteristics of short-distance oil enrichment around the fault, and the development area of fracture deserts near the fault sand body should be the key area for further exploration.

Source Rock Evaluation of Some Mesozoic and Paleozoic Rocks, Faghur Basin, Neith Field, North Western Desert, Egypt

Faghur Basin is one of the most important hydrocarbon provinces inthe northern Western Desert of Egypt. Some of the Mesozoic (Alam ElBueib and Khatatba formations) and Paleozoic rocks at this basin wereevaluated as source rocks based on certain parameters including: thequantity, quality and maturation of the contained organic matter.PetroMode 1D software was used for the construction and prediction ofgeological and geochemical models. Results from organic geochemicalanalysis have clarified that the TOC, HI, S1, S2, %Ro and Tmax values ofAlam El Bueib source rock units range from 0.27 to 6.39 wt.%, 34 to114 mg/g, 0.12 to 0.38 mg/g, 0.23 to 4.3 mg/g, 0.58 to 1.07 % and 409to 450 oC, respectively. While for the Khatatba source rock these valuesrange from 0.41 to 30.09 wt.%, 27 to 155 mg/g, 0.1 to 0.53 mg/g, 0.15 to26.41 mg/g, 1.02 to 1.09 %, 363 to 454 oC, respectively. As for thePaleozoic source rock they are ranging from 0.53 to 4.83 wt.%, 52 to136 mg/g, 0.06 to 0.4 mg/g, 0.29 to 6.57 mg/g, 0.97 to 1.1 % and 406 to467 oC, respectively. Such results indicate that the Alam El Bueib sourcerocks are characterized by type (III) kerogen while Khatatba andPaleozoic source rocks are of type (III) kerogen with inputs of kerogentype (II). Burial history analysis indicates that most of these source rocksare mature and reached their maximum temperature at Neogene time.

First Direct Dating of Alteration of Paleo-Oil Pools Using Rubidium-Strontium Pyrite Geochronology

Direct dating of petroleum systems by hydrocarbon or associated authigenic minerals is crucial for petroleum system analysis and hydrocarbon exploration. The precipitation of authigenic pyrite in petroliferous basins is commonly genetically associated with hydrocarbon generation, migration, accumulation, or destruction. Pyrite rubidium-strontium (Rb-Sr) isotope dilution thermal ionization mass spectrometry (ID-TIMS) is a well-developed technique, and its successful application for high-temperature ore systems suggests that this dating method has the potential to directly date key processes in the low-temperature petroleum systems. Rb-Sr data for pyrites in two Ordovician carbonate rock specimens collected from ~4952 m in the YD-2 well in the Yudong region, northern Tarim Basin (NW China), yield two identical isochron ages within analytical uncertainties: 206 ± 13 (2σ) and 224 ± 28 Ma (2σ). SEM investigations demonstrate that Rb and Sr atoms mainly reside in the crystal lattice of the pyrites due to the absence of fluid and mineral inclusions. The rigorous Rb-Sr isochron relations documented in the samples indicate that such residency can result in sufficient Rb/Sr fractionation and initial Sr isotopic homogenization for geochronology. In addition, the closure temperature (227–320 °C) for the Rb-Sr isotope system in pyrite is higher than the precipitation temperature for pyrite in petroleum-related environments (below 200 °C), suggesting that the Rb-Sr age of pyrite was not overprinted by post-precipitation alteration. Integrating the lead-strontium-sulfur isotopes of the pyrites with burial history analysis, the ages are interpreted as the timing of alteration of the paleo-oil pool by a hydrothermally-triggered thermochemical sulfate reduction process. This study, for the first time, demonstrates that Rb-Sr pyrite geochronology, combined with radiogenic and stable isotopic analyses, can be a useful tool to evaluate the temporal evolution of oil pools. This approach bears great potential for dating of petroleum systems anywhere else in the world.

Controls on the deposition and preservation of architectural elements within a fluvial multi-storey sandbody

Architectural elements of fluvial multi-storey sandbodies provide principal controls on the distribution of meso-scale (100–101 m scale) heterogeneity and reservoir quality. Consequently, it is valuable to understand the deposition and preservation of sedimentary architecture in such systems in relation to autogenic (stream capture and avulsion) and allogenic controls (subsidence rates, climate and sediment supply). The aims of this study are to quantify the architectural and erosional nature of a fluvial multi-storey sandbody and to establish the effects of downstream distance and subsidence rates upon the preservation of architectural elements, using the Lower Castlegate Sandstone, Utah, USA, as an example. Quantitative architectural element analysis and palaeodischarge reconstructions were undertaken from eight locations using sedimentary logs and three terrestrial photogrammetric outcrop datasets along a 150 km down-dip profile. These observations were supplemented by burial history analysis of ten wells across the same profile. Results show the Lower Castlegate comprises channel-fill, downstream accretion, lateral accretion, upstream accretion and overbank elements. From these observations, calculations of sinuosity and flow depths along with architectural geometric analysis provide evidence of stream capture contemporaneous with foreland basin subsidence. The preservation of lateral accretion and overbank elements is limited within the distal portion of the multi-storey sandbody, as a result of local avulsion and limited subsidence rates. Results demonstrate that complex sedimentary architecture can form in fluvial multi-storey sandbodies as a product of variable discharge rates, the fluvial graded profile and spatially variable aggradation rates, driven principally by subsidence rates. The use of meso-scale architectural analysis, with analysis of in-channel sinuosity and hydrodynamics, along with erosional bounding surfaces, has helped to complemented basin-scale interpretations of fluvial architecture.

Simulation of multi-period tectonic stress fields and distribution prediction of tectonic fractures in tight gas reservoirs: A case study of the Tianhuan Depression in western Ordos Basin, China

Abstract Hydraulic fracturing technology, which is emerging in low- or ultralow-permeability oil and gas and tight gas reservoirs, has become a key technology for improving the development efficiency and economic benefit of unconventional gas reservoirs. The success rate of hydraulic fracturing is closely related to the development and distribution of natural fractures. Data obtained from outcrops, cores, thin sections and image logging were used to determine the developmental characteristics of tectonic fractures in the study area to obtain a quantitative forecast of the distribution of gas reservoir fractures in the Tianhuan Depression. With the aid of burial history analysis, geologic interpretation, seismic inversion, logging evaluation, rock mechanics and acoustic emission tests, 3D geomechanical models were established using the finite element method in Tianhuan Depression to simulate the paleotectonic stress fields during Indosinian, Yanshanian and Himalayan periods. The effects of different rock mechanics parameters on the development and distribution of tectonic fractures were identified. A fracture density model was established to determine the quantitative development of tectonic fractures in the upper He8 Member during the production of multi-period tectonic stress fields. The validity of the fracture density model was verified by the fracture statistics of drill core density and gas well productivity tests. Favorable areas for hydraulic fracturing were also determined. Simulation results indicate that the maximum and minimum principal stresses and the maximum shear stress during the Indosinian, Yanshanian and Himalayan periods are controlled by the distribution of the sand body. Rock mechanics parameters play important roles in the development of tectonic fractures in the sedimentary basin with less faults and folds. The 3D models of the multi-period tectonic stress fields and density calculation modelling are not only significant for tight gas sandstone reservoirs but also for predicting of other reservoir fractures.

Tectonostratigraphic evolution of Enjefa’s marginal marine Holocene deposits: highlighting the final stage of Kuwait’s emergence

The Enjefa Beach outcrop comprises marginal marine deposits that are scarcely studied and its facies architecture is largely unknown. With only a few outcrops left in Kuwait, this locality provides an opportunity to better understand the interaction between tectonics and sedimentary processes during the late Holocene, unraveling the final uplift and emergence of Kuwait. Detailed facies analysis revealed that Enjefa outcrop is composed of shoreface and tidal channel facies associations, stacked in a shoaling-upward sequence. One hundred forty-nine paleocurrent measurements were taken at the Enjefa and surrounding areas to understand depositional trends. 2D-structural restoration of seismic data crossing the Ahmadi Ridge was performed along with burial history analysis of a well drilled on the crest of the structure. Facies analysis revealed that the Enjefa outcrop is composed of six depositional facies. These are middle shoreface, upper shoreface, foreshore, lateral accretion, tidal channel, and channel fill/abandonment facies. It is observed that all lateral accretion packages exhibit a unidirectional northern trend. Tectonostratigraphic time-laps simulation revealed that the Ahmadi Ridge final uplift had a direct influence on the tidal channel migration patterns, resulting in a dominant northern migration direction. These results are found to correlate with other Arabian Gulf regions, indicating a regional extent of the late Holocene tectonics.

Diagenesis, burial history, and hydrocarbon potential of Cambrian sandstone in the northern continental margin of Gondwana: A case study of the Lalun Formation of central Iran

Undeformed Cambrian–Ordovician sandstones on the northern margin of Gondwana are in places important hydrocarbon reservoirs. The factors that favoured diagenetic preservation of porosity in such sandstones are reviewed and compared to the Lower Cambrian Lalun Formation of central Iran, in order to assess what aspects of geological history have controlled the cementation and porosity of the sandstones. The Lalun Formation is up to 640 m thick and comprises braided-fluvial sandstones with minor shales that are overlain by marine shales, sandstones and carbonates. In four sections along a ∼650 km traverse, the sandstones are predominantly quartzarenites, locally arkosic and lithic, and contain minimal detrital matrix. Provenance analysis and paleoflow suggest derivation from the Arabian Shield. Diagenesis was dominated by quartz overgrowths and abundant intra-grain microfractures healed by silica cement, with modest amounts of poikilotopic and mosaic calcite, authigenic clay, and iron oxide as early grain rims and late-stage fracture fills. Minor phases include dolomite, ankerite, siderite, magnetite and barite. Marine strata contain more carbonate cement, with silica cement prominent in topmost nearshore sandstones. Burial-history analysis suggests relatively rapid burial in a cratonic setting to more than 4 km by the end of the Silurian and a maximum temperature of ∼150 °C during burial diagenesis, sufficient for hydrocarbon generation by the end of the Paleozoic. Dissolution of K-feldspar, ferromagnesian grains and, locally, calcite cement generated secondary porosity, but porosity and permeability values are low, averaging 1.5% and <0.1 mD, respectively. Rapid subsidence of thick Cambrian fluvial successions at the northeastern Gondwanan margin may have limited early dissolution and promoted occlusion of primary porosity by quartz overgrowths, limiting permeability pathways for fluids that might have generated secondary porosity later in the basinal history. In contrast with Cambrian and Ordovician sandstone reservoirs across North Africa and the Middle East, the existence of Paleozoic source rocks may be problematic in central Iran.

Diagenetic evolution and its implication for reservoir quality: a case study from the Eocene Es4 interval, Dongying Depression, Bohai Bay Basin, China

Petrographic analysis combined with thin section observation, fluid inclusions, burial history analysis, and core porosity and permeability, were used to determine diagenetic evolution and its effect on reservoir-quality of beach-bar sandstone reservoirs of Eocene Es4s interval in the Boxing sag, Bohai Bay Basin. Diagenesis is mainly characterized by strong compaction, undercompaction, cementation of carbonate, quartz, pyrite and clay minerals, dissolution of detrital grains and carbonate cements, lime-mud matrix recrystallization and hydrocarbon filling. Paragenetic sequence is determined as “early compaction / precipitation of calcite, dolomite and framboidal pyrite → dissolution of feldspar grains and early-formed carbonate cements/precipitation of quartz → hydrocarbon filling → precipitation of ferroan calcite and ankerite/lime-mud matrix recrystallization → dissolution of ferroan carbonate cements”. In the same diagenetic environment, diagenetic processes for different lithofacies significantly varied and subsequently resulted in great heterogeneity for reservoir quality during progressive burial. Lithofacies for both bar body and beach edge subfacies which are far from sandstone-mudstone contacts, are well sorted and have a strong ability to resist compaction. Abundant primary and secondary porosities are well developed because of modifications by acidic dissolution and hydrocarbon filling. The present physical properties are relatively well and numerous oil beds are developed through shallow to deep burial depth. Lithofacies for both bar body and beach edge subfacies which are adjacent to sandstone-mudstone contacts, are typically characterized by extensive cementation of calcite and dolomite. The present physical properties are bad and dry beds are extensively developed for sandstone reservoirs in both bar body and beach edge subfacies which are adjacent to sandstone-mudstone contacts. Lithofacies for both bar edge and beach mat subfacies were deposited in weak hydrodynamic conditions with high contents of limemud matrix. The reservoir porosity decreases continually due to strong compaction and weak dissolution. The present physical properties are extremely poor and dry beds are commonly developed through shallow to deep burial except for minor oil beds developed in the shallow burial.

Influence of natural fractures on gas accumulation in the Upper Triassic tight gas sandstones in the northwestern Sichuan Basin, China

The Upper Triassic Xujiahe Formation in the northwestern Sichuan Basin, China, is a typical tight gas sandstone reservoir that contains natural fractures and has an average porosity of 1.10% and air permeability less than 0.1 md because of compaction and cementation. According to outcrops, cores and image logs, three types of natural fractures, namely, tectonic, diagenetic and overpressure-related fractures, have developed in the tight gas sandstones. The tectonic fractures include small faults, intraformational shear fractures and horizontal shear fractures, whereas the diagenetic fractures mainly include bed-parallel fractures. According to thin sections, the microfractures also include tectonic, diagenetic and overpressure-related microfractures. The diagenetic microfractures consist of transgranular, intragranular and grain-boundary fractures. Among these fractures, intraformational shear fractures, horizontal shear fractures and small faults are predominant and significant for fluid movement. Based on the Monte Carlo method, these intraformational shear fractures and horizontal shear fractures improve the reservoir porosity and permeability, thus serving as an important storage space and primary fluid-flow channels in the tight sandstones. The small faults may provide seepage channels in adjacent layers by cutting through layers. In addition, these intragranular and grain-boundary fractures increase the connectivity of the tight gas sandstones by linking tiny pores. The tectonic microfractures improve the seepage capability of the tight gas sandstones to some extent. Low-dip angle fractures are more abundant in the T3X3 member than in the T3X2 and T3X4 members. The fracture intensities of the sandstones in the T3X3 member are greater than those in the T3X2 and T3X4 members. The fracture intensities do not always decrease with increasing bed thickness for the tight sandstones. When the bed thickness of the tight sandstones is less than 1.0 m, the fracture intensities increase with increasing bed thickness in the T3X3 member. Fluid inclusion evidence and burial history analysis indicate that the tectonic fractures developed over three periods. The first period was at the end of the Triassic to the Early Jurassic. The tectonic fractures developed during oil generation but before the matrix's porosity and permeability reduced, which suggests that these tectonic fractures could provide seepage channels for oil migration and accumulation. The second period was at the end of the Cretaceous after the matrix's porosity and permeability reduced but during peak gas generation, which indicates that gas mainly migrated and accumulated in the tectonic fractures. The third period was at the end of the Eogene to the Early Neogene. The tectonic fractures could provide seepage channels for secondary gas migration and accumulation from the Upper Triassic Xujiahe Formation into the overlying Jurassic Formation.

Hydrocarbon charge history of the Paleogene reservoir in the northern Dongpu Depression, Bohai Bay Basin, China

The hydrocarbon charge history of the Paleogene in the northern Dongpu Depression was analyzed in detail based on a comprehensive analysis of the generation and expulsion history of the major hydrocarbon source rocks, fluorescence microscopic features and fluid inclusion petrography. There were two main stages of hydrocarbon generation and expulsion of oil from the major hydrocarbon source rocks. The first stage was the main hydrocarbon expulsion stage. The fluorescence microscopic features also indicated two stages of hydrocarbon accumulation. Carbonaceous bitumen, asphaltene bitumen and colloidal bitumen reflected an early hydrocarbon charge, whereas the oil bitumen reflected a second hydrocarbon charge. Hydrocarbon inclusions also indicate two distinct charges according to the diagenetic evolution sequence, inclusion petrography features combined with the homogenization temperature and reservoir burial history analysis. According to these comprehensive analysis results, the hydrocarbon charge history of the Paleogene reservoir in the northern Dongpu Depression was divided into two phases. The first phase was from the late Dongying depositional period of the Oligocene to the early uplift stages of the late Paleogene. The second phase was from the late Minghuazhen period of the Pliocene to the Quaternary. Reservoirs formed during the first period were widely distributed covering the entire area. In contrast, reservoirs formed during the second period were mainly distributed near the hydrocarbon generation sags. Vertically, it was characterized by a single phase in the upper layers and two phases in the lower layers of the Paleogene.

Deep reservoir quality prediction using diagenesis: a case study from Zhanjiaduo Oilfield of Subei Basin, China

Diagenesis study is used to predict deep reservoir quality in Zhanjiaduo Oilfield of Subei Basin. Based on the thin section, scanning electron microscopy, X-ray diffraction, and burial history analysis, it is found that with a significant burial depth, the third Member of Funing Formation shows good reservoir potential, which is believed to be the result of weak compaction. Abnormally high pressures caused by undercompaction lead to the development of intergranular pores in sandstones. Quartz overgrowth and ferroan calcite cementation are inhibited due to relatively high contents of clay, the premature sealing of the diagenesis system, and a short high-temperature experience. Therefore, the reservoir quality is dominated by clay cementation, and compaction is the most important factor to control reservoir physical properties. Under the same conditions of abnormally high pressures, the compaction loss rate of bar sandstones is lower than that of beach sandstones, so the bar sandstones in a high-pressure area are likely to become reservoirs with good quality. Studies over abnormally high pressure, sedimentary facies, and diagenesis reveal that the high-quality bar sandstones exist in the deep sag area. This finding has been validated by recent exploration wells which obtained high industrial oil flow.

Source rock characterization of the Albian Kazhdumi formation by integrating well logs and geochemical data in the Azadegan oilfield, Abadan plain, SW Iran

Abstract There are several source rock units in the Zagros Basin. Nevertheless, the Cretaceous Kazhdumi formation has presumably produced the majority of the commercial hydrocarbons in this area. The presence of organic matter rich and thermally mature rock units containing oil or gas prone kerogen is the key factor controlling the hydrocarbon generation potential. Owing to the lack of organic geochemical studies such a potential is poorly investigated in the Azadegan oilfield. In this study, firstly we investigate the lower Cretaceous Kazhdumi formation potential source rock based on geochemical parameters including type and amount of kerogen and thermal maturity, obtained from analyzing 45 cutting samples from 9 wells by using Rock-Eval 6 apparatus. Moreover, vitrinite reflectance measurements were carried out on 11 samples utilizing Zeiss Axioplan II microscope for further examination of the thermal maturation. Burial history analysis and thermal maturity modeling suggests that Kazdumi formation is marginally mature (vitrinite reflectance in the range of 0.5–0.7%) with hydrocarbon expulsion beginning since about 14 Ma. The results indicate increasing maturity from south to the north as a result of burial deepening of the Kazhdumi Formation. It contains type II and mixed types II/III kerogen with TOC (Total Organic Carbon) values up to 4.88 wt% and Source Potential Index (SPI) value of 3.72 t HC/m 2 providing a moderate source for the hydrocarbons encountered in the reservoir rocks. In the second part of this research, we attempt to characterize the Kazhdumi source rock by using intelligent systems. In this regard, a three-layered back-propagation Artificial Neural Network (ANN) with Levenberg–Marquardt (LM) training algorithm was designed to predict TOC values from well log data (RHOB, THOR, SGR, NPHI, DT). This network is capable of predicting TOC with correlation coefficient of 98.63% and 82.62% and MSE of 0.0067 and 0.1772 for training and testing steps, respectively. According to the ANN modeling and TOC distribution map, organic richness of the Kazhdumi formation increases from south to the north over the study area.

Tectonic fracture and its significance in hydrocarbon migration and accumulation: a case study on middle and lower Ordovician in Tabei Uplift of Tarim Basin, NW China

Middle and lower Ordovician carbonate rock in the Tabei Uplift of the Tarim Basin forms important fractured reservoir beds. Core and log data indicate that tectonic fractures, as the main fractures in the Tabei Uplift, could be mainly classified into two types: oblique fractures and approximately vertical fractures. The fractures are mainly NNW‐trending and NNE‐trending, coincident with the large faults nearby. Fracture abundance was also controlled by lithology, and faults nearby played a significant role. Cores, thin sections and tests show that these carbonate rocks have as much as 2.5% fracture porosity and as much as 150 md fracture permeability. Based on the intersection of fractures in cores, together with fluid inclusion temperature data, and the timing of faulting from seismic profiles, tectonic fractures were considered to be mainly formed in three periods: the late Silurian when the first‐stage oblique fractures were formed, the late Permian when approximately vertical fractures were formed, and the late Tertiary when the second‐stage oblique fractures were formed. Lower Cambrian source rocks started to enter the stage of generous hydrocarbon generation and expulsion in the Silurian. Ordovician source rocks started to enter the stage of generous hydrocarbon generation and expulsion in the Permian and enter the over‐mature stage in the late Tertiary when light oil was generated. Timing of tectonic fractures formation and burial history analysis suggest that fractures formation might coincide with oil accumulation when fractures provided the pathway and storage space for the low permeability and low porosity reservoir beds caused by previous compaction and cementation. Considering the presence of a large amount of fracture‐developed dolomite in the deeper Ordovician Penglaiba Formation, the undrilled Penglaiba Formation should be paid more attention. Copyright © 2015 John Wiley &amp; Sons, Ltd.

Fractured tight sandstone oil and gas reservoirs: A new play type in the Dongpu depression, Bohai Bay Basin, China

Although conventional reservoirs dominate the Bohai Basin, China, a new type of sandstone reservoir also exists in the Dongpu depression that has a low matrix porosity (tight) in which natural fractures govern both permeability and porosity. These fractured sandstones are located on a structurally modified buried hill underlying Paleogene mudstones, and are truncated along an angular unconformity. The fractured sandstone oils of the Triassic Liujiagou, Heshanggou, and Ermaying Formations are derived from the Paleogene Shahejie Formation, which reached peak oil generation and expulsion during the Oligocene to early Miocene (32.8–15.6 Ma). Gas was generated primarily during the Paleogene from Carboniferous and Permian coals. Petrographic evidence suggests that oil and gas emplacement followed the compaction and cementation of the Triassic sandstone reservoirs. Fluid inclusion evidence and burial history analysis suggest that fractures developed before oil emplacement but may have coincided with peak gas generation, which suggests that oil and gas mainly migrated and accumulated in fractures.

Thin- and thick-skinned salt tectonics in the Netherlands; a quantitative approach

AbstractThe Zechstein salt in the Dutch part of the North Sea Basin played a key role in the generation of successful petroleum plays. This is not only because of its sealing capacity, but also because the salt occurs in structures that provide lateral and vertical traps. The structural styles of areas with thick salt and those with none- or thin salt are completely different during phases of extensional or compressional tectonics. This indicates that, indirectly, the depositional thickness of the main Zechstein salt is essential in regulating the loci of the Dutch petroleum systems. In this paper we aim at quantifying current ideas on the relationship between 1) depositional salt thicknesses; 2) structural style of the main structural elements identified in the Dutch subsurface; 3) timing of deformation; and 4) thickness of the overburden. By finalisation of TNO's subsurface mapping program (see Kombrink et al., this issue), several data products are available that allow evaluation of these relationships. The depositional thickness of the salt was estimated using iterative smoothing of the present day thickness, the results of which account both for regional thickness variations and volume preservation (99%). Fault-distribution analysis shows that faults are only able to penetrate salt with a depositional thickness of &lt;300 m, a transition that demarcates the division between thin- and thick-skinned salt tectonics. In the southern offshore where the salt is thin or absent, the overburden shows the same fault pattern throughout the stratigraphic sequence. In the northern realm, where salt is thicker than 300 m, the salt layer acted as decollement and sub- and supra salt strain are dissimilar. A strong genetic and temporal relationship exists between periods of regional tectonism, halokinetic intensity and thickness distribution of the Zechstein overburden. This relationship is further proven by burial history analysis across two selected profiles in the northern offshore. The analysis focuses on the vertical distribution of the salt by taking into account the depositional and erosional history of the salt overburden, without a-priori defined periods of salt flow. The results corroborate the notion that platforms and highs experienced less extension during the major phases of Jurassic rifting and further suggest that the absence of a thick Jurassic overburden precludes major salt flow during this tectonic phase. Main salt flow was triggered during the Sub-Hercynian and later phases of compression resulting in salt pillow geometries. In the basinal areas, where the Jurassic succession is thickest, salt diapirs and walls formed that are almost exclusively linked to major subsalt faults. Main salt flow occurred during Late Kimmerian rifting, whereas some minor structuration occurred during Sub-Hercynian inversion.