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1.
As shale oil occurs primarily in micro–nano pores and fractures, research about the effect of pore structure on shale oil accumulation has great significance for shale oil exploration and development. The effect of pore structure on shale oil accumulation in the lower third member of the Shahejie formation (Es3l), Zhanhua Sag, eastern China was investigated using gas adsorption, soxhlet extraction, nuclear magnetic resonance (NMR) analysis, and field emission scanning electron microscope (FE-SEM) observation. The results indicated that the samples contained a larger amount of ink-bottle-shaped and slit-shaped pores after extraction than before extraction. The pore volume and specific surface area of the samples were approximately 2.5 times larger after extraction than before extraction. Residual hydrocarbon occurred primarily in the free-state form in pores with diameters of 10–1000 nm, which can provide sufficient pore volume for free hydrocarbon accumulation. Therefore, pores with diameters of 10–1000 nm were regarded as “oil-enriched pores”, which are effective pores for shale oil exploration, whereas pores with diameters smaller than 10 nm were regarded as “oil-ineffective pores”. Samples with only well-developed small pores with diameters smaller than 1000 nm showed high oil saturation, whereas samples with both small pores and also relatively large pores and micro-fractures presented low oil saturation. As the minimum pore size allowing fluid expulsion is 1000 nm, pores with diameters greater than 1000 nm were considered as “oil-percolated pores”. Large pores and micro-fractures are generally interconnected and may even form a complex fracture mesh, which greatly improves the permeability of shale reservoirs and is beneficial to fluid discharge. 相似文献
2.
Reservoirs where tectonic fractures significantly impact fluid flow are widespread. Industrial-level shale gas production has been established from the Lower Cambrian Niutitang Formation in the Cen'gong block, South China; the practice of exploration and development of shale gas in the Cen'gong block shows that the abundance of gas in different layers and wells is closely related to the degree of development of fractures. In this study, the data obtained from outcrop, cores, and logs were used to determine the developmental characteristics of such tectonic fractures. By doing an analysis of structural evolution, acoustic emission, burial history, logging evaluation, seismic inversion, and rock mechanics tests, 3-D heterogeneous geomechanical models were established by using a finite element method (FEM) stress analysis approach to simulate paleotectonic stress fields during the Late Hercynian—Early Indo-Chinese and Middle-Late Yanshanian periods. The effects of faulting, folding, and variations of mechanical parameters on the development of fractures could then be identified. A fracture density calculation model was established to determine the quantitative development of fractures in different stages and layers. Favorable areas for shale gas exploration were determined by examining the relationship between fracture density and gas content of three wells. The simulation results indicate the magnitude of minimum principal stress during the Late Hercynian — Early Indo-Chinese period within the Cen'gong block is −100 ∼ −110 MPa with a direction of SE-NW (140°–320°), and the magnitude of the maximum principal stress during the Middle-Late Yanshanian period within the Cen'gong block is 150–170 MPa with a direction of NNW-SSE (345°–165°). During the Late Hercynian — Early Indo-Chinese period, the mechanical parameters and faults play an important role in the development of fractures, and fractures at the downthrown side of the fault are more developed than those at the uplifted side; folding plays an important role in the development of fractures in the Middle-Late Yanshanian period, and faulting is a secondary control. This 3-D heterogeneous geomechanical modelling method and fracture density calculation modelling are not only significant for prediction of shale fractures in complex structural areas, but also have a practical significance for the prediction of other reservoir fractures. 相似文献
3.
The geochemical and petrographic characteristics of saline lacustrine shales from the Qianjiang Formation, Jianghan Basin were investigated by organic geochemical analysis, X-ray diffraction (XRD), scanning electron microscopy (SEM) and low pressure nitrogen adsorption analysis. The results indicate that: the saline lacustrine shales of Eq3 member with high oil content are characterized by type I and type II oil-prone kerogen, variable TOC contents (1.0–10.0 wt%) and an early-maturity stage (Ro ranges between 0.41 and 0.76%). The mineral compositions of Eq3 saline shale show strong heterogeneity: brittle intervals with high contents of quartz and carbonate are frequently alternated with ductile intervals with high glauberite and clay contents. This combination might be beneficial for oil accumulation, but may cause significant challenges for the hydraulic stimulation strategy and long-term production of shale oil. The interparticle pores and intraparticle pores dominate the pore system of Eq3 shale, and organic matter hosted pores are absent. Widely distributed fractures, especially tectonic fractures, might play a key role in hydrocarbon migration and accumulation. The pore network is contributed to by both large size inorganic pores and abundant micro-factures, leading to a relatively high porosity (2.8–30.6%) and permeability (0.045–6.27 md) within the saline shale reservoir, which could enhance the flow ability and storage capacity of oil. The oil content (S1 × 100/TOC, mg HC/g TOC and S1, mg HC/g rock) and brittleness data demonstrate that the Eq33x section has both great potential for being a producible oil resource and hydraulic fracturing. Considering the hydrocarbon generation efficiency and properties of oil, the mature shale of Eq3 in the subsidence center of the Qianjiang Depression would be the most favorable zone for shale oil exploitation. 相似文献
4.
生烃是地层有机质生成油气的化学平衡。由于油气的密度低于干酪根,它是典型的体积增大化学反应。与实验室开放系统不同,地层有机质生烃反应能等于活化能加排烃能。成熟阶段的地层比较致密,排烃能较大,与开放系统相比,形成了欠生烃。构造运动形成裂隙网,大大降低地层排烃能,使欠生烃的有机质短时间集中生烃,笔者称之为构造生烃。成熟地层通常较致密,排烃能较高,较多欠生烃有机质成为页岩气的物质基础。致密地层在过成熟条件下还有大量欠生烃有机质。经典生烃理论认为Ro大于2.0就基本不生烃,而许多Ro达到3.0,个别甚至4.0的页岩气发现,证明欠生烃的存在。分子越小,排烃能越低,相对致密地层生气的反应能通常最低,更多的有机质形成了页岩气,页岩气资源潜力巨大。页岩气的开采速度比地层自然排烃速度高出多个数量级,天然气排出最快的,最有利于生成天然气的化学平衡。勘探开发实践表明页岩含气量与其TOC成正比,笔者认为这正好预示着页岩中存在游离气、吸附气和有机质的化学平衡。游离气压降低,吸附气就会解吸附;吸附气解吸附,有机质就会生烃。有些过成熟岩石存在未—低成熟度Tmax值。这样低的Tmax值预示着,有机质能够在地层被压裂后随着排烃能的降低而满足反应条件,而成为潜在资源。页岩气的开采与普通气层相比更复杂、更漫长、更巨大。 相似文献
5.
东海西湖凹陷浙东中央背斜带烃源岩生排烃史研究 总被引：9，自引：1，他引：9
为了深化西湖凹陷浙东中央背斜带油气成藏过程的研究，优化勘探目标选择，在烃源岩特征分析的基础上，应用动态数值模拟技术，定量恢复了研究区主要烃源岩层系的生排烃历史，研究表明，浙东中央背斜带主要发育4套烃源岩系，其中始新统平湖组泥岩与煤层为主力烃源岩，具较高的有机质丰度=生烃强度与排烃效率，烃类排出具阶段性、多期次幕式排烃的特点汉平湖组为源岩的油气系统应是本区油气勘探的主要目标。 相似文献
6.
Fractures not only control the distribution of oil and gas reservoirs, but also are key points in the research of oil and gas reservoir development programmes. The tectonic fractures in the Lower Cambrian shale reservoirs in the Feng'gang No. 3 block are effective reservoir spaces for hydrocarbon accumulation, and these fractures are controlled by palaeotectonic stress fields. Therefore, quantitatively predicting the development and distribution of tectonic fractures in the Lower Cambrian shale reservoir is important for the exploration and exploitation of shale gas in the Feng'gang No. 3 block. In the present study, a reasonable geological, mechanical and mathematical model of the study area was established based on the faults systems interpreted from seismic data, fracture characteristics from drilling data, uniaxial and triaxial compression tests and experiments on the acoustic emissions (AE) of rocks. Then, a three-dimensional (3-D) finite element method is applied to simulate the palaeotectonic stress field with the superposition of the Yanshan and Himalayan movements and used to predict the fracture distribution. The simulation results indicate that the maximum principal stress value within the study area ranged from 269.97 MPa to 281.18 MPa, the minimum principal stress ranged from 58.29 MPa to 79.64 MPa, and the shear stress value ranged from 91.05 MPa to 106.21 MPa. The palaeotectonic stress field is controlled by the fault zone locations. The fracture development zones are mainly controlled by the tectonic stress fields and are located around the faults, at the end of the fault zones, at the inflection point and at the intersection of the fault zones. 相似文献
7.
Stress, fluid and temperature are three of the major factors that impact natural gas migration and accumulation. In order to study the influences of tectonic stress field on natural gas migration and accumulation in low-permeability rocks, we take the Kuqa Depression as an example and analyze the evolution of the structure and tectonic stress field at first. Then we study the influences of tectonic stress field at different tectonic episodes on fractures and fluid potentials through the numerical simulation method on the section across the KL2 gas field. We summarize two aspects of the impact of the tectonic stress field on natural gas migration and accumulation. Firstly, under the effects of the tectonic stress field, the rock dilation increases with the added stress and strain, and when the shear stress of rock exceeds its shear strength, the shear fractures are well developed. On one hand, the faults which communicate with the hydrocarbon source rocks become the main pathways for natural gas migration. On the other hand, these positions where fractures are well developed near faults can become good reservoirs for natural gas accumulation. Secondly, because fluid potentials decrease in these places near the faults where fractures are well developed, natural gas can migrate rapidly along the faults and accumulates. The impact of tectonic stress fields on natural gas migration and accumulation allows for hydrocarbon migration and accumulation in the low-permeability rocks in an active tectonic compressive setting. 相似文献
8.
The microstructure of black siliceous shale from the lower Cambrian Niutitang Formation, Sichuan Basin in China was investigated by the combination of field emission scanning electron microscope (FE-SEM) and argon ion beam milling. The nanometer-to micrometer-scale pore systems of shales are an important control on gas storage and fluid migration. In this paper, the organic porosity in shale samples within oil and gas window has been investigated, and the formation mechanism and diagenetic evolution of nanopores have been researched.FE-SEM reveals five pore types that are classified as follows: organic nanopores, pores in clay minerals, nanopores of framework minerals, intragranular pores in microfossils, and microfractures. Numerous organic nanopores are observed in shales in the gas window, whereas microfractures can be seen within the organic matter of shales in the oil window. Microfractures in oil window shales could be attributed to pressure buildup in the organic matter when incompressible liquid hydrocarbon are generated, and the orientation of microfractures is probably parallel to the bedding and strength anisotropy of the formation. Pores in clay minerals are always associated with the framework of clay flakes, and develop around rigid mineral grains because the pressure shadows of mineral grains protect pores from collapse, and the increasing of silt content would lead to an increase in pressure shadows and improve porosity. Nanopores of rock framework are probably related to dissolution by acidic fluids from hydrocarbon generation, and the dissolution-related pores promote permeability of shales. Porosity in the low-TOC, low-thermal-maturity shales contrast greatly with those of high-TOC, high-thermal-maturity shales. While the high-TOC shales contain abundant organic microporosity, the inorganic pores can contribute a lot to the porosity of the low-TOC shales. 相似文献
9.
10.
Belinda Larsen Agust Gudmundsson Ivar Grunnaleite Gunnar Sælen Michael R. Talbot Simon J. Buckley 《Marine and Petroleum Geology》2010
The permeability of a reservoir is particularly dependent upon the proportion of its fractures that penetrate or are arrested at interfaces such as contacts and discontinuities. Here we report on fracture penetration and fracture arrest in Lower Cretaceous peritidal deposits exposed in the Pizzicoli Quarry, Gargano Promontory, southern Italy. We measured more than 2000 fractures, in the field and using LIDAR data, of which 564 fractures from the field and 518 from LIDAR studies are the focus of this paper. Fracture arrest/deflection and penetration depend much on the effects of peritidal cycle interfaces such as paleosol horizons, laminated carbonate mudstones, and stylonodular horizons. The laminated mudstones have the greatest effect; 63–99% of the fractures are deflected or arrested at such interfaces, whereas 63–90% are deflected/arrested at paleosols, and 20–35% at stylonodular horizons. In the mudstones, many fractures are arrested at thin, internal laminae, such that few penetrate the entire laminated layer, and fewer still the boundaries between the layers. Paleosol interfaces deflect/arrest more than 60% of all fractures. However, when small-offset fractures above and below paleosols are regarded as penetrating, they are evenly spaced (non-clustered), so that fracture-related fluid transport may occur across the entire paleosol. Stylonodular horizons deflect/arrest and split some fractures, but generally have little effect compared with the other types of interfaces. We present three main mechanisms for fracture deflection and/or arrest: (1) the fracture-induced tensile stress ahead of its tip, referred to as the Cook-Gordon debonding mechanism; (2) rotation of the principal stresses at and across the interface, resulting in the formation of stress barriers; and (3) large elastic mismatch (particularly as regards Young’s moduli) between layers across an interface. All these mechanisms are likely to have operated during fracture propagation and arrest in the carbonate rocks of the Pizzicoli Quarry. 相似文献
11.
《Marine and Petroleum Geology》1988,5(3):293-297
Geometric form of kerogen patches control oil-induced fracturing in impermeable source rocks. Thin elongate kerogen flakes cause lateral fracturing. Kerogen has to occur in spherical or cylindrical forms to induce vertical fractures. If length to width ratio of kerogen flakes is sufficiently large, then lateral fractures are definitely initiated during oil generation in impermeable source rock. Oil and rock compressibilities, and lateral to vertical stress ratio are decisive factors in vertical fracturing in impermeable rocks. Lateral to vertical stress ratio is generally higher than the maximum for oil-induced vertical fracturing in tectonically relaxed sedimentary basins. Oil generation cannot initiate vertical fractures, except when the lateral to vertical stress ratio is reduced below critical level either by tectonic tension or erosion of overburden.When the source rock is permeable, then the rate of oil seepage from kerogen into the surrounding rock is crucial in fracture initiation. Oil-induced fractures cannot form unless permeability, and hence rate of oil seepage from kerogen into the surrounding rock, is non-existent or negligible. Most source rocks have some permeability. Therefore, oil-induced fracture initiation should be a rare phenomenon. 相似文献
12.
Palaeopressure reconstruction to explain observed natural hydraulic fractures in the Cleveland Basin
Natural fractures observed within the Lower Jurassic shales of the Cleveland Basin show evidence that pore pressure must have exceeded the lithostatic pressure in order to initiate horizontal fractures observed in cliff sections. Other field localities do not show horizontal fracturing, indicating lower pore pressures there. Deriving the burial history of the basin from outcrop, VR and heat-flow data gives values of sedimentation rates and periods of depositional hiatus which can be used to assess the porosity and pore pressure evolution within the shales. This gives us our estimate of overpressure caused by disequilibrium compaction alone, of 11 MPa, not sufficient to initiate horizontal fractures. However, as the thermal information shows us that temperatures were in excess of 95 °C, secondary overpressure mechanisms such as clay diagenesis and hydrocarbon generation occurred, contributing an extra 11 MPa of overpressure. The remaining 8.5 MPa of overpressure required to initiate horizontal fractures was caused by fluid expansion due to hydrocarbon generation and tectonic compression related to Alpine orogenic and Atlantic opening events. Where horizontal fractures are not present within the Lower Jurassic shales, overpressure was unable to build up as high due to proximity to the lateral draining of pressure within the Dogger Formation. The palaeopressure reconstruction techniques used within this study give a quick assessment of the pressure history of a basin and help to identify shales which may currently have enhanced permeability due to naturally-occurring hydraulic fractures. 相似文献
13.
The influence of oil-expulsion efficiency on nanopore development in highly mature shale was investigated by using anhydrous pyrolysis (425–600 °C) on solvent-extracted and non-extracted shales at a pressure of 50 MPa. Additional pyrolysis studies were conducted using non-extracted shales at pressures of 25 and 80 MPa to further characterize the impact of pressure on pore evolution at high maturity. The pore structures of the original shale and relevant artificially matured samples after pyrolysis were characterized by using low-pressure nitrogen and carbon-dioxide adsorption techniques, and gas yields during pyrolysis were measured. The results show that oil-expulsion efficiency can strongly influence gas generation and nanopore development in highly mature shales, as bitumen remained in shales with low oil expulsion efficiency significantly promotes gaseous hydrocarbon generation and nanopore (diameter < 10 nm) development. The evolution of micropores and fine mesopores at high maturity can be divided into two main stages: Stage I, corresponding to wet gas generation (EasyRo 1.2%–2.4%), and Stage II, corresponding to dry gas generation (EasyRo 2.4%–4.5%). For shales with low oil expulsion efficiency, nanopore (diameter < 10 nm) evolution increases rapidly in Stage I, whereas slowly in Stage II, and such difference between two stages may be attributed to the changes of the organic matter (OM)’s mechanical properties. Comparatively, for shales with high oil expulsion efficiency, the evolution grows slightly in Stage I, not as rapidly as shales with low efficiency, and decays in Stage II. The different pore evolution behaviors of these two types of shales are attributed to the contribution of bitumen. However, the evolution of medium–coarse mesopores and macropores (diameter >10 nm) remains flat at high maturation. In addition, high pressure can promote the development of micropores and fine mesopores in highly mature shales. 相似文献
14.
《Marine and Petroleum Geology》2012,32(1):110-124
The transport properties of Permian to Miocene oil shales (Torbanite, Posidonia, Messel, Himmetoglu, and Condor) were studied using petrophysical and geochemical techniques. The aims of this study were to assess permeability of oil shales, evaluate the evolution of porosity, specific surface area and intergranular permeability during high temperature compaction tests and to verify the suitability of intergranular permeability for petroleum expulsion. Measured permeability coefficients for two samples were 0.72 × 10−21 m² for the Eocene Messel shale and 2.63 × 10−21 m² for the Lower Jurassic Posidonia shale from S. Germany, respectively. BET specific surface areas of the original samples ranged from 0.7 to 10.6 m²/g and decreased after compaction to values from 0.3 to 3.7 m²/g. Initial porosity values ranged from 7.6 to 20.1 % for pre-deformation and from 9.99 to 20.7 % for post-deformation samples. Porosity increased during the high-temperature compaction experiments due to petroleum generation and expulsion. Permeability coefficients estimated using the Kozeny–Carman equation varied from 6.97 × 10−24 m² to 5.22 × 10−21 m² for pre-deformation and from 0.2 × 10−21 m² to 4.8 × 10−21 m² for post-deformation samples reflecting the evolution of their porosity and BET specific surface areas. Measured and calculated permeability were similar for the Messel shale whereas calculated permeability was two orders of magnitude lower for the Posidonia shale from S. Germany. Petroleum expulsion efficiencies under the experimental conditions ranged from 38.6% for the Torbanite to 96.2% for the Posidonia shale from S. Germany. They showed strong positive correlation with the petroleum generation index (R² = 0.91) and poor correlations with porosity (R² = 0.46), average pore throat diameters (R² = 0.22), and compaction (R² = 0.02). Estimated minimum pore-system saturations for petroleum expulsion during the experiments were 12% for the Torbanite and 30% for the Posidonia shale from N. Germany. Pore-system saturation determines whether expulsion occurs mainly through matrix or fracture permeability. For samples with saturation levels above 20%, fracture permeability dominated during the experiments. Evidence based on the measured permeability coefficients, expulsion flow rates, consideration of capillary displacement during generation-related pore invasion and the existence of transport porosity suggests that fracture permeability is the principal avenue of petroleum expulsion from source rocks. This conclusion is supported by microscopic observations. 相似文献
15.
The quality of source rocks plays an important role in the distribution of tight and conventional oil and gas resources. Despite voluminous studies on source rock hydrocarbon generation, expulsion and overpressure, a quality grading system based on hydrocarbon expulsion capacity is yet to be explored. Such a grading system is expected to be instrumental for tight oil and gas exploration and sweet spot prediction. This study tackles the problem by examining Late Cretaceous, lacustrine source rocks of the Qingshankou 1 Member in the southern Songliao Basin, China. By evaluating generated and residual hydrocarbon amounts of the source rock, the extent of hydrocarbon expulsion is modelled through a mass balance method. The overpressure is estimated using Petromod software. Through correlation between the hydrocarbon expulsion and source rock evaluation parameters [total organic carbon (TOC), kerogen type, vitrinite reflectance (Ro) and overpressure], three classes of high-quality, effective and ineffective source rocks are established. High-quality class contains TOC >2%, type-I kerogen, Ro >1.0%, overpressure >7Mpa, sharp increase of hydrocarbon expulsion along with increasing TOC and overpressure, and high expulsion value at Ro >1%. Source rocks with TOC and Ro <0.8%, type-II2 & III kerogen, overpressure <3Mpa, and low hydrocarbon expulsion volume are considered ineffective. Rocks with parameters between the two are considered effective. The high-quality class shows a strong empirical control on the distribution of tight oil in the Songliao Basin. This is followed by the effective source rock class. The ineffective class has no measurable contribution to the tight oil reserves. Because the hydrocarbon expulsion efficiency of source rocks is controlled by many factors, the lower limits of the evaluation parameters in different basins may vary. However, the classification method of tight source rocks proposed in this paper should be widely applicable. 相似文献
16.
R. Mourgues J.B. GressierL. Bodet D. BureauA. Gay 《Marine and Petroleum Geology》2011,28(5):1111-1121
In petroleum industry, the difference between pore pressure (Pp) and minimum horizontal stress Sh (termed the seal or retention capacity) is of major consideration because it is often assumed to represent how close a system is to hydraulic failure and thus the maximum hydrocarbon column height that can be maintained. While Sh and Pp are often considered to be independent parameters, several studies in the last decade have demonstrated that Sh and Pp are in fact coupled. However, the nature of this coupling relationship remains poorly understood. In this paper, we explore the influences of the spatial pore pressure distribution on Sh/Pp coupling and then on failure pressure predictions and trap integrity evaluation. With analytical models, we predict the fluid pressure sustainable within a reservoir before failure of its overpressured shale cover. We verify our analytical predictions with experiments involving analogue materials and fluids. We show that hydraulic fracturing and seal breach occur for fluid pressure greater than it would be expected from conventional retention capacity. This can be explained by the impact of the fluid overpressure field in the overburden and the pressure diffusion around the reservoir on the principal stresses. We calculate that supralithostatic pressure could locally be reached in overpressured covers. We also define the retention capacity of a cover (RC) surrounding a fluid source or reservoir as the difference between the failure pressure and the fluid overpressure prevailing in shale at the same depth. In response to a localized fluid pressure rise, we show that the retention capacity does not only depend on the pore fluid overpressure of the overburden but also on the tensile strength of the cover, its Poisson’s ratio, and the depth and width of the fluid source. 相似文献
17.
The northwestern part of the Persian Gulf is one of the most prominent hydrocarbon exploration and production areas. Oilfields are located in structural highs formed around the Cenomanian depression known as Binak Trough. To evaluate the highly variable source rock maturity, timing of hydrocarbon generation as well as migration pattern and the remaining hydrocarbon potential of the early Cretaceous source rocks, burial and thermal histories were constructed for four production wells and one pseudo well. In addition two cross sections covering the depression and the structural highs around the trough were investigated by 2D basin modeling to provide a better regional overview on basin evolution.The modeling results indicate that whereas the Cretaceous source rocks are immature or early mature at the location of oilfields, they reached sufficient maturity to generate and expel considerable amounts of hydrocarbons in the Binak depression. The main phase of oil generation and expulsion from the Cretaceous source rocks is relatively recent and thus highly favorable for the conservation of hydrocarbon accumulations. Trap charging occurred through the late Miocene to Pliocene after the Zagros folding. 2D models predict that the Albian source rock still has significant hydrocarbon generation potential whereas the lower Neocomian source rock has reached already a high transformation ratio within the deep kitchen area. Oil migration occurs in both lateral and vertical directions. This migration pattern could explain the distribution of identified oil families in the northwestern part of the Persian Gulf. 相似文献
18.
The Wufeng-Longmaxi organic-rich shales host the largest shale gas fields of China. This study examines sealed fractures within core samples of the Wufeng-Longmaxi shales in the Jiaoshiba shale gas field in order to understand the development of overpressures (in terms of magnitude, timing and burial) in Wufeng-Longmaxi shales and thus the causes of present-day overpressure in these Paleozoic shale formations as well as in all gas shales. Quartz and calcite fracture cements from the Wufeng-Longmaxi shale intervals in four wells at depth intervals between 2253.89 m and 3046.60 m were investigated, and the fluid composition, temperature, and pressure during natural fracture cementation determined using an integrated approach consisting of petrography, Raman spectroscopy and microthermometry. Many crystals in fracture cements were found to contain methane inclusions only, and aqueous two-phase inclusions were consistently observed alongside methane inclusions in all cement samples, indicating that fluid inclusions trapped during fracture cementation are saturated with a methane hydrocarbon fluid. Homogenization temperatures of methane-saturated aqueous inclusions provide trends in trapping temperatures that Th values concentrate in the range of 198.5 °C–229.9 °C, 196.2 °C-221.7 °C for quartz and calcite, respectively. Pore-fluid pressures of 91.8–139.4 MPa for methane inclusions, calculated using the Raman shift of C-H symmetric stretching (v1) band of methane and equations of state for supercritical methane, indicate fluid inclusions trapped at near-lithostatic pressures. High trapping temperature and overpressure conditions in fluid inclusions represent a state of temperature and overpressure of Wufeng-Longmaxi shales at maximum burial and the early stage of the Yanshanian uplift, which can provide a key evidence for understanding the formation and evolution of overpressure. Our results demonstrate that the main cause of present-day overpressure in shale gas deposits is actually the preservation of moderate-high overpressure developed as a result of gas generation at maximum burial depths. 相似文献
19.
The Paraná Basin, southern Brazil, has an atypical thermal and fluid history due to the occurrence of an episodic continental flood volcanism during the Early Cretaceous. So far, there are few data about the influence of this volcanic event on the paleotemperatures and paleofluids of the Paraná Basin sedimentary rocks. The Teresina Formation in the northern flank of the Ponta Grossa dyke swarm hosts high concentration of subsurface igneous rock bodies (sills and dykes), besides its covering by a hundreds meter thick volcanic rock cap. In this study, we used fluid inclusion analysis performed in horizontal and vertical calcite veins from the Teresina Formation and from a Late Cretaceous basic dyke to estimate paleotemperatures and to characterize the composition of diagenetic paleofluids. Homogenization temperatures of requilibrated fluid inclusions show that the Teresina Formation reached temperatures above 200 °C. Horizontal parallel bedding calcite veins from the Teresina Formation record low to high salinity (2–26 wt.% NaCl eq.) aqueous paleofluids. The prevalence of high salinity fluid inclusions associated with light hydrocarbon fluid inclusions indicates deep buried fluids. Fluid inclusions in vertical calcite vein from basic dyke comprise only low salinity aqueous fluids (0–3 wt.% eq.NaCl) interpreted as dominated by meteoric water. The recorded paleotemperatures are attributed to the heating by the Paraná volcanic event during the Early Cretaceous, with the thermal effect of the volcanic rock cap surpassing the effect of nearby sills and dykes. Estimated paleotemperatures higher than 200 °C would allow the generation of light liquid and gaseous hydrocarbons. Overpressured compartments in the Teresina Formation allowed the expulsion of buried pore fluids (high salinity aqueous fluids and hydrocarbons) to fracture systems, where they mixed with meteoric water. The input of meteoric water through fracture systems connected with the surface favored hydrocarbons degradation in the early stages of source rock maturation during the Early Cretaceous. 相似文献
20.
Understanding the oil distribution characteristics in unconventional tight reservoirs is crucial for hydrocarbon evaluation and oil/gas extraction from such reservoirs. Previous studies on tight oil distribution characteristics are mostly concerned with the basin scale. Based on Lucaogou core samples, geochemical approaches including Soxhlet extraction, total organic carbon (TOC), and Rock-Eval are combined with reservoir physical approaches including mercury injection capillary pressure (MICP) and porosity-permeability analysis, to quantitatively evaluate oil distribution of tight reservoirs on micro scale. The emphasis is to identify the key geological control factors of micro oil distribution in such tight reservoirs. Dolomicrites and non-detrital mudstones have excellent hydrocarbon generation capacity while detritus-containing dolomites, siltstones, and silty mudstones have higher porosity and oil content, and coarser pore throat radius. Oil content is mainly controlled by porosity, pore throat radius, and hydrocarbon generation capacity. Porosity is positively correlated with oil content in almost all samples including various lithologies, indicating that it is a primary constraint for providing storage space. Pore throat radius is also an important factor, as oil migration is inhibited by the capillary pressure which must be overcome. If the reservoir rock with suitable porosity has no hydrocarbon generation capacity, pore throat radius will be decisive. As tight reservoirs are generally characterized by widely distributed nanoscale pore throats and high capillary pressure, hydrocarbon generation capacity plays an important role in reservoir rocks with suitable porosity and fine pore throats. Because such reservoir rocks cannot be charged completely. The positive correlation between hydrocarbon generation capacity and oil content in three types of high porosity lithologies (detritus-containing dolomites, siltstones, and silty mudstones) supports this assertion. 相似文献