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Highlights • Cumulative-In-Situ-Injection-Production is a novel method for reservoir development. • Simulation results indicate CIIP is an efficient energy-supplement method. • CIIP is applicable to many kinds of tight reservoirs with highly irregular fractures. • Technology for Electric fluid regulation system of CIIP still need to be improved. Abstract Water flooding and gas injection are two traditional secondary development methods for tight oil reservoirs. Water injection has the problem of small injectivity due to low permeable reservoir matrix while gas injection brings about severe breakthrough because of obvious viscosity difference between gas and oil. These traditional approaches that supplement energy between wells are not highly effective. To fill this gap, this paper proposes an efficient energy-supplement method, continuous in-situ injection and production (CIIP), among fractures for multistage fractured horizontal well (MFHW) in tight oil reservoirs. CIIP divides hydraulic fractures into two kinds, in which odd fractures are used for production while even fractures are for injection. CIIP has three main advantages over traditional water flooding: firstly, it switches displacement interval from between injection and production wells to between hydraulic fractures; secondly, CIIP has a better injectivity compared to traditional water flooding at the same injection pressure; and thirdly, CIIP improves sweep efficiency thereby improving oil recovery. In this paper, a workflow is developed to evaluate the performance of CIIP in a case study. Reservoir properties and micro-seismic (MS) mapping data are analyzed to provide fundamental parameters for building a numerical simulation model, and then history matching is achieved to validate the model. The simulation considers two scenarios of hydraulic fractures: the uniform and non-uniform fractures. Uniform-fracture simulation aims to investigate the mechanisms of CIIP under three fracture models; different fracture half-lengths and the situation of existing high permeable channels between injection and production fractures are also included in uniform-fracture simulation. Non-uniform-fracture simulation, whose fractures are interpreted according to MS mapping results, is devised to demonstrate CIIP's superiority in a realistic way. This study is based on a theoretical approach and the results wait to be further proven in the field. Simulation results demonstrate that CIIP is an efficient energy-supplement method. It helps to maintain reservoir pressure near the initial condition during the thirty-year simulation. Meanwhile, even if ten injection wells are added, CIIP still injects 55% more water than water injection (WI) at the same injection pressure. Uniform-fracture simulation indicates that CIIP has a 2.23% more oil recovery than WI and a 3.74% than depletion. Besides, the influence of high permeable channels between injection and production fractures is insignificant and we can still expect CIIP's good performance when hydraulic fractures hit local natural fractures. The non-uniform-fracture simulation demonstrates that CIIP performs well too when hydraulic fractures are randomly distributed. It also finds outs that the presence of primary fractures in which proppant concentrates is essential to CIIP while the role of natural fractures is trivial compared to the hydraulic fractures. In a word, CIIP is a promising technology for tight oil reservoir development. [ABSTRACT FROM AUTHOR]

The Qiangtang Basin is one of the largest Mesozoic petroliferous basins in China that is still unexploited for the petroleum industry. The basic geological issues and synthesis of the Qiangtang Basin related to the Tethyan evolution are still poorly understood. This volume presents 20 research papers to address the tectonic settings, basin evolution, and sedimentary environments of the Qiangtang Basin, which are key factors for a better understanding of the overall petroleum system. The Qiangtang Basin holds a Precambrian base developed in response to the Paleo-Tethys Hol Xil-Jinshajiang Ocean evolution, with enhanced sedimentary basin infilling during the opening and expansion of the Neo-Tethys Bangong-Nujiang Ocean in the Mesozoic. The Paleozoic basin framework of the Qiangtang demised as the Paleo-Tethys Ocean closed at the latest Permian, while the Early-Middle Triassic foreland basin underwent a negative basin inversion during the Late Triassic. The latter initiated a new sedimentary filling cycle of the Qiangtang Basin, which was triggered by the active extensional rifting and the onset of the bimodal volcanic eruption. Recent scientific exploratory drilling (QK-1 well) found that the Qiangtang Basin is characterized by multiple source rocks, of which the upper Triassic Bagong Formation and the lower Quse Formation exhibit the most hydrocarbon generation potential. The development of high quality and quantity source rocks in the Qiangtang Basin is ensured by regional to global-scale bottom-water anoxia and high primary productivity in the eastern Tethys realm in the Late Triassic and the Early Jurassic. The main reservoirs in the Qiangtang Basin include the Middle Jurassic reef-beach facies, the Upper Triassic carbonates, and the Lower Jurassic terrestrial clastic rocks. Two very-thick caprocks of gypsum in the Lower Jurassic and gypsum mudstones in the Middle Jurassic strata are found during the scientific drilling, which is interpreted as favorable regional-scale seals for petroleum entrapment in the Qiangtang Basin. [ABSTRACT FROM AUTHOR]

The Tarim Craton of NW China hosts abundant hydrocarbon resources within clastic reservoirs characterized by a complex entrapment and fill history. In this paper, we review the processes of hydrocarbon accumulation in typical clastic reservoirs from the literature, and combine this with new research from six hydrocarbon-bearing regions (the Yakela Faulted-Uplift, the southern slope of the Tabei Uplift, the Tazhong Uplift, the northern slope of the Tazhong Uplift, the southern margin of the Bachu Uplift, and volcanic reservoirs) to identify the key controls on hydrocarbon accumulation and distribution in reservoirs of the Tarim Craton. Favorable reservoir–trap configurations exist on structural highs created during the evolution of paleo-uplifts and paleo-slopes in the region, with hydrocarbons accumulating in both structural (fault, salt dome, and thrust-fault anticline) and combined structural-primary stratigraphic traps. Vertical hydrocarbon migration occurred via deep–shallow superposed faults, and (rarely interpreted) fault textures in volcanic conduits. Unconformity surfaces and sand bodies provided pathways for both limited lateral redistribution and significant long-distance (>100 km) migration of hydrocarbons. The prospectivity of upper Paleozoic sandstone facies and paleogeography was controlled by denudation of the paleo-uplifts, and these reservoirs are most likely to host giant oil and gas fields in the region. • Differential hydrocarbon accumulation process of six clastic hydrocarbon abundance zones in Tarim Craton. • Favorable structural reservoir–trap configurations exist on structural highs created during the evolution of Paleo uplifts/slopes. • Vertical hydrocarbon migration occurred via deep–shallow superposed faults, and fault textures in volcanic conduits. • The prospectivity of upper Paleozoic sandstone facies and paleogeography was controlled by denudation of the paleo-uplifts. [ABSTRACT FROM AUTHOR]

Abstract This paper uses coal-measure shales from Carboniferous-Permian in Yushe-Wuxiang Block as an example to study the physical properties of transitional coal measure shales, including geochemical properties (e.g. total organic carbon content (TOC), organic matter maturity and hydrocarbon generation potential); mineral composition determined by X-ray diffraction (XRD) and pore structure characteristics determined by gas adsorption methods. The results indicated that the transitional coal measure shales in Yushe-Wuxiang area mostly comprise type III kerogen and are mostly in the over-mature stage, with shales in the range of 1.86%–3.36% R o. The TOC of transitional shales varied significantly, ranging from 0.10% to 34.37%. Clay minerals and quartz are major minerals in transitional shales, while the predominant clay minerals are illite-smectite mixed clay (I/S) and kaolinite. The total pore volume (TPV) and pore specific surface area (SSA) of investigated mud shales varies from 0.0071 to 0.023 cm3/g and 8.4059–18.2888 m2/g, respectively. The transitional shales mostly provide mesopores and macropores, whereas the micropores provide the main SSA. The TOC content has a distinct effect on the porosity and micropores volume but contributes little to the TPV and volumes of macropores and mesopores. Clay minerals are positively correlated with porosity, TPV and volumes of each class of pores, while quartz has an opposite effect. In the over-maturity stage, the increase of organic matter maturity will inhibit the development level of pores in shale. For the coal measure shales, I/S and illite contribute most to the pore development. Highlights • TOC is positively correlated with porosity and micropore volume. • Clay minerals are positively correlated with pore volumes. • Quartz inhibits the development level of transitional coal measure shales. • The development and evolution of pores was mainly attributed to the presence of I/S and illite. [ABSTRACT FROM AUTHOR]

Abstract: CCS technology is particularly important to China due to its large and rapidly rising emissions and high dependence on fossil fuel. There is a huge basin scale theoretical CO2 storage capacity in China; however the CCS deployments will consider firstly those matched source-sink pairs with early opportunities at present. This paper presents the key results of evaluation of early opportunities for the deployment of CCS technologies within China. The proximity analysis suggests that there also are many early opportunities for CCS deployment, such as the promising EOR/EGR opportunities from using high concentration CO2 sources. The combined benefits of short distance between sources and sinks, the potential hydrocarbon revenues and low CO2 capture cost make these pairs as promising near-term CCS candidates. These near-term CCS candidates can be deployed at very low cost or even with some revenue. In this paper, several sources-sink pairs in China are analyzed in details, such as, the pairs of high purity CO2 emission sources and aquifer, co-storage of waste gas stream and depleted gas fields, IGCC and aquifer. These early opportunities will provide China the chance to develop and spread CCS technologies steadily from early stage to commercial stage. [Copyright &y& Elsevier]

Abstract: The complicated mechanisms governing hydrocarbon expulsion (primary migration) have not as yet been fully understood, though understanding these mechanisms is paramount in basin modeling. This paper presents (a) a simple oil-expulsion model based on the principles of sedimentary compaction and the flow difference between oil and water, and (b) a simple gas-expulsion model via mass balance. These two models do not consider more factors or mechanisms than some existing models, but we verify that the predicated expelled amount is proper by using it as input data for secondary migration and confirming that the modeled volume of accumulated hydrocarbons is close to that determined by exploration. The hydrocarbon migration–accumulation (secondary migration) history is the most important component in basin modeling, but it is also one of the most challenging to achieve. In general, a sectional 2-D simulator cannot predict the amount of hydrocarbon accumulated, whereas a 3-D simulator takes considerable computing time. This paper presents a simplified pseudo 3-D model based on the principles of buoyancy drive and Darcy''s Law in combination with the effects of faulting and lithology on migration pathways. Comparing with the existing four models currently in use (multi-phase Darcy flow, flowpath, hybrid method combining the former two approaches together, and invasion percolation), the proposed model is mainly targeted at calculating the quantities and locations of petroleum accumulations for oil and gas assessment, and so the factors taken into account and the functions needed to be executed in software are less than in other models. Application of the aforementioned three models in the Kuqa Depression of the Tarim Basin in western China shows that the simplified pseudo 3-D model is very efficient and less computationally extensive, and the predicted quantities and locations of petroleum accumulations approach those determined by exploration, showing these models could form a useful prospecting method. [Copyright &y& Elsevier]

Recently, with the ongoing development of the express industry, the consumption of waste plastic express bags has been increasing year by year, which has brought considerable pressure on municipal waste management. At the same time, in China, where coal is the main energy resource, the upgrading of low-rank coal is a more reliable and prospective way. An effective method for waste treatment and resource upgrading by synergistic co-liquefaction of waste plastic express bags and low-rank coal in a supercritical water-ethanol system has been developed. The effects of different experimental factors (temperature, residence time, plastic-coal ratio, water-ethanol ratio) on the conversion ratio and synergistic effect of co-liquefaction were investigated. The results showed that elevated temperature, lower water-ethanol ratio as well as suitable residence time, and plastic-coal ratio of 1:1 were conducive to the conversion ratio. Temperature ≥375 °C and suitable plastic-coal ratio (1:1) had a significant positive synergistic effect on the conversion ratio, whereas the other conditions exhibited no or negative synergistic effect on the conversion ratio. The maximum conversion ratio and positive synergistic efficiency were 85.11% and 12.25% at 425 °C, 60 min, water-ethanol ratio of 1:1, and plastic-coal ratio of 1:1, respectively. It was observed after FT-IR and elemental analysis based on the solid residue that the oxygen-containing functional groups in the residue disappeared, the oxygen content decreased, the carbon content increased, and the higher heating value (HHV) increased significantly, and the residue could be further used (such as gasification or pyrolysis) without the need for landfill. The GC-MS results of the oil products suggested that the oil products contained high content of hydrocarbons and phenols, as well as esters, alcohols, and other compounds. The hydrocarbons and phenols mainly derived from the decomposition of long chains in plastics and the decomposition of aromatic structures in coal, and the hydrocarbon and phenolic contents produced at 400 °C were 27.74% and 32.62%, respectively. Thus, the oil product can be used further as a chemical raw material. It cannot be ignored that the ethanol medium after reaction can also be further recycled by rotary evaporation. The synergistic co-liquefaction of waste plastic express bags and low-rank coal based on supercritical water-ethanol system is a promising method for waste treatment and resource upgrading. [Display omitted] • A synergistic co-liquefaction for waste express bags and low-rank coal was developed. • Ethanol can improve the synergistic efficiency of co-liquefaction. • The maximum conversion ratio of co-liquefaction reached 85.11% at 425 °C, 60 min. • Oil products from co-liquefaction contained hydrocarbons and phenolic compounds. [ABSTRACT FROM AUTHOR]

Organic-rich rocks have received increasing attention for they are essential for evaluating hydrocarbon potential and unravelling the interaction between Earth surface environments and the biosphere. In this paper, we performed a combination of mineralogical, inorganic and organic geochemical analyses on a 200-m core of the Permian Lucaogou Formation organic-rich rocks obtained from Santanghu Basin, NW China, to investigate paleoenvironmental conditions, organic matter accumulation, and hydrocarbon potential. The redox- and salinity-sensitive proxies (e.g. V/Cr, V/(V + Ni) and Sr/Ba, Rb/K, B/Ga, and B content), together with the wide distribution of pyrite and carbonate minerals in these dark, thinly laminated organic-rich rocks, suggest that dysoxic-anoxic, brackish-saline, alkaline conditions prevailed during the deposition of the Lucaogou Formation in the Santanghu Basin. The occurrence of hydrothermal minerals, including strontianite and barite, and enrichments of B (up to 158.0 ppm), Mn (up to 1291 ppm), and certain incompatible elements (Li (up to 923 ppm), Rb (up to 848 ppm), Sr (up to 1760 ppm), Hf (up to 12.7 ppm)) as well as Ni vs. Co vs. Zn and Fe vs. Mn vs. (Cu + Co + Ni) × 10 ternary diagrams demonstrate that the Lucaogou Formation received hydrothermal input during deposition, which suggests hydrothermalism was the source of brine that has caused the salinization of the water column. The positive correlation of HI value and TOC content, together with redox-sensitive proxies, illustrates primary productivity in surface water and preservation in anoxic bottom water collectively contributed to the enrichment of organic matter. Moreover, the positive correlation between silicate mineral content and TOC content and the negative correlation between carbonate content and TOC content suggest that terrigenous input as the main source of nutrients promoted organic matter accumulation, while carbonate constituents acted as a diluent to organic matter accumulation during deposition of the Lucaogou Formation. The faint positive correlation between TOC content and hydrothermal intensity indicator (Cr/Zr) seems to indicate that hydrothermal fluids may provide an additional source of nutrients for organic matter accumulation. In addition, the oil generation capacity of Lucaogou Formation, with abundant oil-prone organic matter (Type I/II 1 kerogen with HI values ranging from 421.18–918.41 mg HC/g TOC) in the early mature to mature stage (T max values ranging from 435 to 451 °C), is considerable. The Rock-Eval oil saturation index (OSI S 1 /TOC × 100) values range from 6.04–164.07 mg HC/g TOC, suggesting the Lucaogou Formation contains producible oil. The high brittle mineral (including quartz and carbonates) contents (> 50% wt%) and traces of clay minerals (< 5 wt%) imply that the Lucaogou Formation is likely to respond well to hydraulic stimulation. Consequently, the Lucaogou Formation in Santanghu Basin is expected to be a potential lacustrine shale oil play. [ABSTRACT FROM AUTHOR]

Relatively to petroleum exploration on an anticline or in fault block areas in continental basins, the identification of hydrocarbon traps on a synclinalic structure is a challenging task. In order to locate prospects in synclinal areas of Lishu Depression, this study analyzes the structural development of the Qikeshu syncline, describes the sedimentary facies, the sandbody distribution patterns and localizes potential Lishu Depression traps in the syncline based on seismic and well data. Furthermore, the paper summarizes the hydrocarbon trap spatial distribution and discusses the key points points in identifying hydrocarbon traps in faulted-syncline structures of a continental basin. The obtained results show that the tectonic movements at the end of the Barremian and Maastrichtian Ages bounded each limb of the Qikeshu syncline and reoriented paleo-delta lobes deposited in the syncline area. The modifications of the delta lobe affected the distribution of favorable sandbodies and potential hydrocarbon traps. The development of lithologic traps is correlated with the sandbody vertical stacking patterns in a sedimentary sequence. In faulted and folded structures of this continental basin, the post-depositional tectonic modification of paleo-sedimentary bodies strongly influences hydrocarbon play conditions. The petroleum exploration should thus focus on structural history and sedimentary factors, in order to analyze the lithologic and fault-controlled combination traps. [ABSTRACT FROM AUTHOR]

Oil adsorption on the pore surface of tight shale affects the transport and even recovery of oil through shale reservoir. In this paper, an innovative model evaluating the n -alkane adsorption on shale was developed theoretically according to the hydrocarbon vapor adsorption (HVA) process and was verified by the n -decane (i.e., n -C 10 ) adsorption on continental oil shale obtained from the Dongying sag of the southeastern Bohai Bay basin of China. The model considered the multilayer adsorption of hydrocarbon and the microscopic characteristics of the shale pore system. For a case study, several parameters in the models were determined by low temperature nitrogen adsorption/desorption (LT-N 2 A/D) and HVA tests combined with recently reported molecular dynamics simulation. Next, optimal values of the coefficients k and β were determined by fitting the experimental data with the model and were used to calculate the n -C 10 adsorbed amount under 0.8 P / P 0 and 298.15 K condition. Simultaneously, the n -C 10 condensed (i.e., free-phase-like) amount was obtained. The primary results demonstrate that (1) n -C 10 adsorbed amount is obviously lower than condensed amount and varies from 0.097 to 0.619 mg/g (mean 0.311 mg/g), accounting for 1.68–3.76% (mean 2.32%) of the total amount. (2) Both the adsorbed and condensed amounts are directly controlled by total pore volume, which are mainly contributed by organic matters and secondarily by pyrite and siderite in shale. The model will be potential useful to evaluate the shale oil adsorption. [ABSTRACT FROM AUTHOR]

Recent drilling data from the northern Songliao Basin reveal considerable hydrocarbon exploration potential in deep-seated small-scale faulted basins. In this paper, the Shahezi Formation of the northern Xujiaweizi Fault Depression within the Songliao Basin was investigated as a case study. Sequence stratigraphy, sedimentary systems and the hydrocarbon exploration potential of the small-scale faulted basin were investigated through observations and descriptions of cores; analyses of conventional log curves, imaging data and logging data; and interpretations of 3-D seismic profiles. Four third-order sequences, mainly controlled by sediment supply and fault activity, were identified based on unconformities at the basin margins and in sedimentary successions. System tracts in the third-order sequences were also recognized through lithological associations and geophysical response characteristics. The distributions of sedimentary systems, including fan deltas, braided deltas, lacustrine deposits, subaqueous fans, volcaniclastic deposits and incised-valley deposits, in the sequence framework are associated with basin evolution. During the early stage of the Shahezi Formation (SQ1 and SQ2), the sedimentary area was mainly covered by fan deltas, and lacustrine deposits were not very developed. Additionally, incised-valley systems formed on basin margins and subaqueous fans formed along basin-controlled faults. During the middle stage (SQ3), fan delta deposits on gentle slopes were gradually replaced by braided delta deposits, and the sizes of lacustrine facies increased with basin expansion. In the late stage (SQ4), the basin and lacustrine deposit areas reached their maximum sizes, and braided deltas became the dominant sedimentary systems on gentle slopes. With continuous sediment supply, fan and braided deltas migrated forward, and the lacustrine system was locally distributed. In this small-scale faulted basin, the lacustrine mudstones and coal seams widely developed in SQ4, especially in SQ4-HST, and they also exhibited good source rock properties for gas generation. Sandbodies of fan deltas and braided deltas in the upper Shahezi Formation, exhibiting good contact relationships with underlying source rocks, can be favourable reservoirs for hydrocarbon accumulation, as confirmed by the newly drilled Well Songs9H (with a daily gas production of 20×10 4 m 3 ). However, due to low porosity and permeability (averages of 4.7% and 0.28×10 −3 µm 2 , respectively), these reservoirs may need fracturing for commercial hydrocarbon production. [ABSTRACT FROM AUTHOR]

• The sedimentary environment transitioned from clastic shore-shelf of the lower Ediacaran to carbonate platform to mixed shelf of the upper Ediacaran except for the glaciogenic Hangelchaok Formation. • The Ediacaran slop break belt was first identified along the west and south margins of the Manjar sag. • High-quality source rocks and karstic dolostone in Ediacaran indicate great potential for hydrocarbon exploration. The Late Neoproterozoic was an important period for the breakup of Rodinia and the assembly of Gondwana. The Neoproterozoic succession developed under the extensional setting is critical for understanding the early tectono-sedimentary evolution of the Tarim Basin and possibly exhibits considerable hydrocarbon potential. In this paper, the stratigraphic correlation of the Ediacaran is conducted across the whole Tarim Basin, based on the latest wells, seismic data and field investigations. The paleogeographic distribution and hydrocarbon potential of the Ediacaran are thoroughly discussed. The Lower Ediacaran succession is mainly distributed in northern and southwestern Tarim Basin and marginal outcrop areas, but absent in the whole Central Rise. With sea level rising, the Upper Ediacaran succession gradually moved toward Central Rise with the exception of the Tazhong Uplift and the eastern Bachu Uplift. During Early Ediacaran, depositional environment in the Tarim Basin was mainly clastic shore-shelf, with a large denuded region extending from Bachu-Tazhong Uplift to Tadong Uplift. The range of the erosional area gradually diminished during Late Ediacaran. Accordingly, the Tarim Basin was dominated by carbonate platform and mixed shelf. Slope break belt between carbonate platform and mixed shelf was identified around the Manjar sag for the first time. The Ediacaran black mudstone and shale in northeastern and southwestern Tarim, which formed in deep-water environment and have relatively high values of TOC (mostly ranging from 0.3% to 1.2%), can serve as high-quality source rocks. The Upper Ediacaran dolostones altered by paleokarst could be potential reservoir rocks. Our research findings, combining with previous geological results, suggest that the Ediacaran succession in Tarim Basin has great potential for hydrocarbon exploration. [ABSTRACT FROM AUTHOR]

Knowledge of the natural structure properties of coal seams is essential for the coal bed methane (CBM) production because of their great influence on the inner flow characteristics and permeability features of hydrocarbons and water. In this paper, a series of laboratory tests, including nondestructive low-field nuclear magnetic resonance (NMR), scanning electron microscopy (SEM), X-ray computed tomography (CT) and core tests were carried out to characterize the physical structure properties of coal. The pore size distribution, pore type, morphological features and three-dimensional rendering of coal cleat structures are presented. The permeability changes of 7 cylindrical coal cores investigated under a varying effective stress range (0–35Mpa) reveal that coal porosity decreased linearly and coal permeability declined exponentially with the rise of stress; while under higher stress conditions, the occurrence of internal crushing and mechanical damage will result in irreversible change for porosity and permeability. Through the comprehensive analysis based on linking permeability to porosity and CT result, a basic estimation on directional cleat permeability is also realized. This method provides a preliminary but satisfactory estimation for local directional cleat permeability, which reflects that both bedding and non-bedding direction permeability owns great heterogeneity for an individual sample; but face cleat permeability always found to be the largest, and the mean bedding plane permeability value is found usually 3.01–11.68 times lower than face and butt cleat permeability. [ABSTRACT FROM AUTHOR]

The timing of mantle−derived CO 2 charging in sedimentary basins is the basis for studying CO 2 -sandstone interactions and CO 2 -oil interactions. In general, the time of the volcanic eruption near the CO 2 gas reservoir is considered to be the time of mantle-derived CO 2 charging. However, this approach is not suitable for hydrocarbon-bearing basins that have experienced multiple volcanic events. In this paper, using dawsonite-bearing sandstones contained in an oil-bearing CO 2 gas and oil reservoir in the southern Songliao Basin as the object of the study on the basis of paragenetic sequence and fluid inclusions, we establish a mineral dating method for determining the time of mantle-derived CO 2 charging. In this method, the mineral used for dating is dawsonite, which is formed under a high CO 2 partial pressure and records the migration and aggregation of mantle-derived CO 2 in geologic history. By interpreting the dawsonite-bearing sandstone in the southern Songliao Basin, we find two hydrocarbon charges and one CO 2 charge and that the mantle-derived CO 2 charging occurred slightly later than or quasi-simultaneously with the second hydrocarbon filling. Combining the currently known time of hydrocarbon reservoir formation and the time of tectonic fracture development, we deduce that the mantle-derived CO 2 formed the dawsonite in the southern Songliao Basin at the end of the Cretaceous (end of the Mingshui period) and the beginning of the Paleogene. [ABSTRACT FROM AUTHOR]

There are abundant hydrocarbon resources in the deepwater region, so the exploration and development of deepwater oil and gas has become an important strategy for the Chinese petroleum industry. However, well cementing in deepwater, especially the cementing of the surface casing, is challenged due to the low temperature, which requires proper cementing accelerators to make the cement have certain strength at the early stage. Aiming to enhance the cementing quality of the surface casing, two kinds of lithium salt accelerators named LSA-1 and LSA-2 were developed in our early works based on the effects of different salts on oil well cement at low temperatures. In this paper, a comprehensive set of experiments was designed to test the effects of LSA-1 and LAS-2 on the Class-G oil well cement, including observations and measurements of the cement hydration products, the hydration heat and the developments of the static gel strength and the compressive strength. Based on these experiments, we discussed the mechanisms and performances of these two lithium salt accelerators at low temperatures. The experiment results indicate that both LSA-1 and LSA-2 can accelerate the hydration rate by advancing the hydration acceleration period and result in the earlier generation of Ca(OH) 2 and AFt. They can also induce the cement hydration products to form regular and compact gel structures, which contributes to the development of the static gel strength and the compressive strength of cement slurry at the early stage. Moreover, the two lithium salt accelerators have the characteristic of low hydration heat. This is helpful to reconcile the contradiction between the development of cement early compressive strength and the hydration heat, which can help to avoid channeling and hydrate decomposition in the strata containing gas hydrate. In general, LSA-2 has a stronger effect on accelerating hydration of oil well cement, while LSA-1 has less impact on cement hydration heat. Therefore, both LSA-1 and LSA-2 are qualified to serve as low-temperature accelerators for deepwater cementing, which are able to meet the diverse requirements of the deepwater low-temperature environment and the field cementing operation. [ABSTRACT FROM AUTHOR]

Organic-rich shales spanning in age from Pre-Cambrian to Quaternary were widely deposited in China. This paper elaborates the geology and unique characteristics of emerging and potential hydrocarbon-bearing shales in China. The Pre-Cambrian Sinian Doushantuo to Silurian black marine shales in the intra-shelf low to slope environments were accumulated in South China and Tarim Platform in Northwest China. These marine shales with maturity (Ro) of 1.3–5% are in dry gas window. During Carboniferous to Permian, the shales associated with coal and sandstones were mainly deposited in coastal swamp transitional setting in north China, NE China, NW China and Yangtze platform in South China. These transitional shales are generally clay rich and are potential gas-bearing reservoirs. Since Middle Permian, the lacustrine shales with total carbon content (TOC) up to 30% and Ro mainly in oil window are widely distributed in all the producing basins in China. The lacustrine shales usually have more clay mineral content than marine shales and are characterized by rapid facies change and are interbedded with carbonates and sandstone. The high quality shale reservoir with high TOC, hydrocarbon content and brittle minerals content is usually located at transgressive systems tract (TST) to early highstand systems tract (EHST) interval deposited in anoxic depositional setting. Recent commercial shale gas production from the Silurian Longmaxi marine shale in the southeastern Sichuan Basin, preliminary tight oil production associated with lacustrine hydrocarbon-bearing shale intervals and hydrocarbon shows from many other shales have proven the hydrocarbon-bearing shales in China are emerging and potential shale gas and tight (shale) oil plays. Tectonic movements could have breached the early hydrocarbon accumulation in shales and tectonically stable areas are suggested to be favorable prospects for China shale plays exploration and production. [ABSTRACT FROM AUTHOR]

Fault-sealing capability has critical influence on coalbed methane (CBM) accumulation and preservation in coal-bearing basins. Although southern Qinshui Basin is the first commercial CBM production area in China, detailed investigation on faults evolution and its impact on gas accumulation has never been performed. In this paper, the generation time and the evolution process of the sealing capability of seven major faults in the Zhengzhuang field were evaluated by using well-logging data and 3D seismic tectonic interpretation. Results indicate that most normal faults in the Zhengzhuang field were created from Late Cretaceous to Paleogene and after the key stage of hydrocarbon-generation. Fault-sealing capability was evaluated through the vertical pressure on the faults' surface ( VPFS ), the shale gouge ratio ( SGR ) and the clay-smear potential ( CSP ), the values of which for Zhengzhuang field are −3.2 MPa to 16 MPa, 0.36 to 0.91, and 2–40 m, respectively. These values demonstrate that the fault-sealing is complex and variable when the faults present in different scales or different positions in the faulting system. In the Zhengzhuang field, almost all faults exhibit good lateral sealing capability ( LSC ) with high values of SGR (>0.6) and CSP (>15 m) during fault evolution. Therefore, the current gas contents are primarily related to the vertical sealing capability ( VSC) but not to the LSC of the faults. The VSC of the fault varies with the different stages during the fault evolution. In the Late Cretaceous-Paleogene, a key stage for gas dissipation, almost all faults possess low VSC, which caused generally low gas content (<22.4 m 3 /t) near the faults. In contrast, the gas content that was not affected by faults is commonly >25 m 3 /t. In the Neogene-Quaternary, the VSC was variable for different faults. For the faults with low VSC, they would gradually lead to low gas content. The results showed that the VSC positively correlated with the current gas contents near the faults in the Zhengzhuang field, southern Qinshui Basin, North China. [ABSTRACT FROM AUTHOR]

China has carried out several drilling campaigns for natural gas hydrate both in marine and terrestrial areas and successfully obtained the samples. The marine gas hydrate samples were firstly recovered from Shenhu area in 2007 and then from the Pearl River Mouth basin in 2013 in South China Sea (SCS). The terrestrial gas hydrate samples were recovered from Qilian Mountain permafrost (QMP) in 2009 and 2013, respectively. In this paper, systematic analyses have been carried out on these gas hydrate samples to compare the characteristics of gas hydrates from SCS with those from QMP. The results indicate that the characteristics of occurrence, structure and gas composition are obviously different. Marine gas hydrate from SCS shows different kinds of occurrence and demonstrates a typical structure I (sI), with cage occupancy of more than 99% methane in large cage and 90% in small cage, respectively, corresponding to hydration numbers of approximately 6.0 by thermodynamic calculation. The guest molecules are predominantly methane (> 99%) from biogenic origin produced by CO 2 reduction. However, the terrestrial gas hydrates from QMP occur as a thin layer within the cracks of fine-grained sandstones, siltstones and mudstones, showing a possible structure II (sII) hydrate based on its Raman spectra and gas composition. The molecular composition of hydrate-bound gas indicates that CH 4 only accounts for ~ 60% of the guests while the others are heavier hydrocarbons (e.g. C 2 H 6 , C 3 H 8 and C 4 H 10 ).The cage occupancy ratio of methane in small and large cage (θ S /θ L ) is around 7.5, suggesting that larger molecules preferentially occupy the large cage of the hydrate. The isotopic analysis shows that hydrate-bound gases in QMP are from thermogenic origin. [ABSTRACT FROM AUTHOR]

Organic-rich black shale and dark-grey mudstone are widespread in the Seventh Member of the Yanchang Formation, Ordos Basin. There are obviously differences in geochemical characteristics and hydrocarbon generation potential between black shale and dark-grey mudstone. Based on the detailed organic geochemical examination, this paper reveals the differences in hydrocarbon generation processes and characteristics (activation energy and conversion rate of hydrocarbon generation) between dark-grey mudstone and black shale and the causes for the differences. Black shale is characterized by moderate to very high total organic carbon (TOC) contents (5.08%–39.39%) and its kerogen type belongs to type II 1 and type I. Dark-grey mudstone has a characteristic of low to moderate TOC contents (0.64%–7.35%) and its kerogen types are mainly composed of type II 2 and type II 1. The hydrocarbon generation activation energy of black shale mainly oscillates around 250–310 KJ/mol, and the corresponding hydrocarbon generation threshold is high (the simulated temperature is 400 °C). The process of hydrocarbon generation is characterized by fast conversion rate and short cycle. By contrast, the hydrocarbon generation activation energy of dark-grey mudstone has a wide range (170–360 KJ/mol), and the corresponding hydrocarbon generation threshold is low (the simulated temperature is 230 °C). The process of hydrocarbon generation is characterized by slow conversion rate and long cycle. The difference of hydrocarbon generation process and characteristics between black shale and dark-grey mudstone is mainly affected by macerals composition and organic matter source. The organic matter of black shale mainly originated from algae, and its macerals was mainly composed of alginite. The organic matter of dark-grey mudstone mainly originated from the mixture of algae and terrestrial higher plants (conifers), and its macerals was mainly composed of vitrinite, liptodetrinite and inertinite. The complex macerals composition and organic matter source make the activation energy distribution of dark-grey mudstone more dispersed than that of black shale. In addition, affected by the macerals (e.g sporinite and resinite) with low activation energy from terrestrial higher plants, the activation energy of dark-grey mudstone containing sporinite and resinite in the macerals is lower than black shale. Therefore, the dark-grey mudstone containing algae and terrestrial higher plants corresponds to low hydrocarbon generation threshold, slow conversion rate and long hydrocarbon generation cycle. The black shale containing a large number of algae corresponds to high hydrocarbon generation threshold, fast conversion rate and short hydrocarbon generation cycle. Moreover, the conversion rate of black shale containing radioactive elements and more clay minerals is higher than that of dark-grey mudstone. • Detailed comparison of hydrocarbon generation characteristics, molecular composition and organic petrology between mudstone and shale in the Chang 7 Member. • The difference of hydrocarbon generation potential between mudstone and shale is mainly affected by paleo-productivity and preservation environment. • The difference of hydrocarbon generation characteristics between mudstone and shale is mainly affected by macerals composition and organic matter source. [ABSTRACT FROM AUTHOR]

The nuclear magnetic resonance (NMR) technique is a crucial means for formation evaluation. It can provide an accurate set of formation parameters in single-phase-flow reservoirs, such as porosity, permeability, and pore structure distribution; however, in most cases, there are hydrocarbon-water two-phase fluids in the reservoirs. The secondary change of the T 2 distribution makes the accuracy of the evaluation a challenge. Hence, it is necessary to clarify the impact of changes in hydrocarbon content on the response of NMR signals before using the traditional evaluation methods. In this paper, we analyzed the response mechanism of NMR T 2 distribution under different saturation conditions. Based on the theoretical derivation, we established a nuclear magnetic model that describes the relation among the T 2 geometric mean value of water signal, hydrocarbon signal, and water saturation. The accuracy of each model part was verified by numerical simulation. In addition, the calculation results in core samples show that the proposed model is more effective and reliable than two existing models (the T2 saturation ratio model and the Xiao empirical model), especially in extreme conditions (irreducible water and hydrocarbon saturated samples). Finally, we applied the proposed model to field application in the Tertiary formation in the Bohai Bay Basin, China, which achieved good effects in the NMR fluid substitution and the NMR saturation evaluation. • The relation among NMR T 2gm of the water, hydrocarbon signal and the water saturation could be expressed mathematically. • A new model was established for characterizing the NMR response in hydrocarbon bearing rocks. • Compared with the traditional model, the new model was proved to be better regional adaptability and stability. • The model could be used for NMR fluid substitution and saturation evaluation in hydrocarbon bearing formation. [ABSTRACT FROM AUTHOR]

Abstract: The petroliferous central Junggar Basin in northwest China is predominantly an oil exploration region. However, its gas exploration also might have good prospects. Thus to assist in gas exploration, the geochemistry and origins of gases are discussed in this paper based on relatively comprehensive analyses of compositions, carbon isotopes and light hydrocarbons of gases. Based on the results, the gas genetic types are grouped into families and combined with the geological setting (e.g., biomarkers of retrograde condensates and source rock characteristics). We show that there are four representative genetic types of gases. The first consists of gases derived from Permian lacustrine mudstones with type I–II kerogen and type III kerogen sources in the Penyijingxi sag. Their representative geochemical feature is δ13C2 ranging from −31.4‰ to −24.7‰. The second is gas sourced from Carboniferous tufaceous mudstones of type III kerogen in the Dishuiquan sag, whose representative geochemical feature is the heaviest values of δ13C1 in the studied samples, ranging from −32.0‰ to −30.4‰. The third consists of gases sourced from Jurassic coals and mudstones in the Shawan–Fukang sag. The light hydrocarbon fingerprints of these gases are similar to those of gases and oils typically derived from Jurassic source rocks in the southern Junggar Basin. The fourth is gas most likely generated from the degradation of crude oil. It is mainly found in the Luliang area and has dryness values as much as 0.999 and δ13C1 ranging from −54.8‰ to −43.2‰. Among these four types of gases, the first (mainly sourced from the Permian lacustrine mudstones in the Penyijingxi sag) is the predominant type. [Copyright &y& Elsevier]

Abstract: Vitrinite reflectance (VR, Ro%) measurements from residual kerogen of pyrolysis experiments were performed on immature Maoming Oil Shale substituted the samples for the gas-prone source rocks of Yacheng formation of the Qiongdongnan Basin in the South China Sea. The work was focused on determination an upper limit of maturity for gas generation (ULMGG) or “the deadline of natural gas generation”. Ro values at given temperatures increase with increasing temperature and prolonged heating time, but ΔRo-value, given a definition of the difference of all values for VR related to higher temperature and adjacent lower temperature in open-system non-isothermal experiment at the heating rate of 20°C/min, is better than VR. And representative examples are presented in this paper. It indicates that the range of natural gas generation for Ro in the main gas generation period is from 0.96% to 2.74%, in which ΔRo is in concordance with the stage for the onset and end of the main gas generation period corresponding to 0.02% up to 0.30% and from 0.30% up to 0.80%, respectively. After the main gas generation period of 0.96–2.74%, the evolution of VR approach to the ULMGG of the whole rock for type II kerogen. It is equal to 4.38% of VR, where the gas generation rates change little with the increase of maturation, ΔRo is the maximum of 0.83% corresponding to VR of 4.38%Ro, and the source rock does not nearly occur in the end process of hydrocarbon gas generation while Ro is over 4.38%. It shows that it is the same the ULMGG from the whole rock for type II kerogen as the method with both comparison and kinetics. By comparing to both the conclusions of pyrolysis experiments and the data of VR from the source rock of Yacheng formation on a series of selected eight wells in the shallow-water continental shelf area, it indicate that the most hydrocarbon source rock is still far from reaching ULMGG from the whole rock for type II kerogen. The source rock of Yacheng formation in the local areas of the deepwater continental slope basin have still preferable natural gas generative potential, especially in the local along the central depression belt (namely the Ledong, Lingshui, Songnan and Baodao sags from southwest to northeast) from the depocenter to both the margin and its adjacent areas. It help to evaluate the resource potential for oil and gas of the hydrocarbon source rock in the deepwater continental slope of the Qiongdongnan Basin or other basins with lower exploration in the northern of the South China Sea and to reduce the risk in exploration. [Copyright &y& Elsevier]

Abstract: The Daxing conglomerate reservoir has become an important exploration target in the Langgu Depression of the Bohai Bay Basin. In this paper, gravel composition, void space, poroperm characteristics and hydrocarbon productivity of the Daxing conglomerate in the third member of the Oligocene Shahejie Formation (Es3) are studied in detail to understand the impact of gravel type on reservoir quality based on cores, petrographic thin-sections, scanning electron microscope (SEM) photos, porosity, permeability and well test data. The Daxing conglomerate is composed of limestone and dolomite gravels. The void space of the Daxing conglomerate includes intragravel and intergravel pores as well as fissures. Intragravel pores are dominated by gravel type. They develop as intergranular pores, intergranular dissolved pores, intragranular dissolved pores and few intercrystalline pores in limestone gravels, whereas in dolomite gravels they develop as intercrystalline pores, intercrystalline dissolved pores, dissolved pores and cavities, few intergranular pores and intergranular dissolved pores. The analysis shows that dolomite conglomerates provide better reservoir quality than limestone conglomerates. Microscopically, areal porosity in dolomite gravels is higher than that in limestone gravels. Macroscopically, porosity and permeability of conglomerates that are dominated by dolomite gravels (dolomite conglomerates) are better than those of conglomerates dominated by limestone gravels (limestone conglomerates). The dolomite conglomerates are superior to the limestone conglomerate with regard to hydrocarbon productivity at the level of parent rock and gravel properties. Poroperm characteristics and hydrocarbon productivity of dolomite reservoirs in the middle Proterozoic Changcheng and Jixian Systems (parent rocks of dolomite gravels) are better than those of the limestone reservoirs in the lower Paleozoic, Cambrian and Ordovician (parent rocks of limestone gravels). Gravel properties, including grain structure, physical nature and dissolution velocity cause the dolomite conglomerates to have more intercrystalline pores, fissures and secondary dissolved pores than limestone conglomerates. [Copyright &y& Elsevier]

Abstract: Vertical distributions of air pollutants are crucial for understanding the key processes of atmospheric transport and for evaluating chemical transport models. In this paper, we present measurements of non-methane hydrocarbons (NMHCs) and halocarbons obtained from an intensive aircraft study over northeast (NE) China in summer 2007. Most compounds exhibited a typical negative profile of decreasing mixing ratios with increasing altitude, although the gradients differed with different species. Three regional plumes with enhanced VOC mixing ratios were discerned and characterized. An aged plume transported from the northern part of the densely populated North China Plain (NCP; i.e. Beijing–Tianjin area) showed relatively higher levels of HCFC-22, 1,2-dichloroethane (1,2-DCE) and toluene. In comparison, the plume originating from Korea had higher abundances of CFC-12, tetrachloroethene (C2Cl4) and methyl chloride (CH3Cl), while regional air masses from NE China contained more abundant light alkanes. By comparing these results with the earlier PEM-West B (1994) and TRACE-P (2001) aircraft measurements, continuing declining trends were derived for methyl chloroform (CH3CCl3), tetrachloromethane (CCl4) and C2Cl4 over the greater China–northwestern Pacific region, indicating the accomplishment of China in reducing these compounds under the Montreal protocol. However, the study also provided evidence for the continuing emissions of several halocarbons in China in 2007, such as CFCs (mainly from materials in stock) and HCFCs. [Copyright &y& Elsevier]

Abstract: Greenhouse gas (GHG) emission from geological sources such as volcanic activity, seabed gas hydrate release, hydrocarbon seepage as well as uncontrolled combustion of fossil fuels is erratic and difficult to quantify. In this paper we assess the GHG emission due to spontaneous combustion of in-situ coal deposits (‘coal fires’). This problem is aggravated by human intervention (mining activities) which on the other hand allows better constrained estimations and improved reduction strategies, provided modern mining practices are employed. In this study we present three case studies on coal fire-related GHG emission quantification on provincial scale in China, and we propose an integrated quantification aimed at the joint analyses of local knowledge, geophysical data, and remote sensing data with the objective to retrieve unbiased numbers. As a first estimate, we conclude that the emissions of GHGs from coal fires in China account for well less than 0.22% of all global fossil fuel related CO2 emissions, most likely even less than 0.1%. This is much less than the previously estimated 2–3%. [Copyright &y& Elsevier]

Abstract: The continuing increases in oil prices have renewed the argument over the real culprits behind these movements. The growth in demand for oil in international markets, especially from the United States and China, is often identified as the main source of consumption pressure on prices, and thus the upward trend in oil prices. This paper uses unit root tests with two endogenous breaks to analyze the characteristics of oil prices, production, and consumption for several countries. By taking into account structural breaks, we find that many countries’ oil consumption and oil prices are stationary, while other countries are not. We also perform causality tests to determine the direction of any possible relationship between oil price and oil consumption and production. Our statistical analysis reveals that production variables cause oil prices, while oil prices tend to cause consumption. As a result, we claim that the blame for the recent fluctuations in oil prices is more appropriately associated with supply factors, not consumption influences. [ABSTRACT FROM AUTHOR]

Abstract: The Yuka depression is located in the north margin in Qaidam Basin, Qaidam Basin is an interior formed primarily in the Mesozoic and Cenozoic. There are extensive distribution of good source rocks of middle Jurassic, which have undergone non-uniform uplift, twisting and deep burying. There are different hydrocarbon generation (HG) evolutions. We have studied the history of burying, heating, and hydrocarbon generation of the Jurassic source rocks not just on the basis of tectonic disturbance and deep burying in detail. Meanwhile, Combining with fluid inclusion measurements and the numerical simulation of EASY%Ro, We analysis the evolution process, the tectonic stages and the intensity of the HG of middle Jurassic source rock. The hydrocarbon generation occurred in Yanshanian and Early Himalayan since the middle Jurassic formation. The paper discusses tarp formation and destroys of the oil & gas in Yuka depression. At last, we suggest that the thrust fault of Late Himalayan must be pay more attention, .and the middle or small sizes of oil & gas fields will be discovered in the future exploration. [Copyright &y& Elsevier]

Abstract: The light hydrocarbons of oils play an important role in their geochemistry, especially in mixed oils. The database of the Key Laboratory of Petroleum Geochemistry, China National Petroleum Corporation has accumulated 824 oil sample records. The oil samples represent most of the oil areas of China. In this paper the light hydrocarbons of salt lake derived oils from Jianghan basin, China, were studied. These oils are characterized by high toluene contents and high K 1 [K 1 =(2-MH+2,3-DMP)/(3-MH+2,4-DMP)] values. The reason is unclear but may be related to the high salinity environment of the source. [Copyright &y& Elsevier]

Abstract: Hydrocarbon migration pathways are the linkage between hydrocarbon source areas and accumulation sites. Modeling accurately the pathways of hydrocarbon migration is of important significance in determining the location of favorable petroleum exploration targets. In this paper, GIS-based modeling algorithms are presented for searching the pathways of secondary hydrocarbon migration by considering the geologic mechanisms. These algorithms are constructed on a raster digital elevation model (DEM) of the top boundary of a carrier bed, in which secondary migration occurred. On the DEM, a 3×3 pixel sized window is used for searching. The center of the search window is initially assumed at a point on the boundary of a hydrocarbon source area, from which the secondary hydrocarbon migration starts. The altitude values in the eight adjoining pixels enclosing the central pixel of the search window are compared, and the pixel with an altitude value not only larger than the central pixel but also the largest of the eight surrounding pixels is the next target pixel where the search window will move to. Each searched path will terminate at either a convex point, which indicates the existence of a trap for hydrocarbon accumulation, or a point on the boundary of the DEM, which suggests that the pathway of hydrocarbon migration extends outside the DEM. In addition, a concourse point of two paths is also considered as a termination point of either path. The algorithms were successfully applied in the modeling of the secondary migration pathways in the northern Songliao Basin, northeast China. The modeled results matched well with drilling data, suggesting the robustness of the algorithms. [Copyright &y& Elsevier]

Large-scale lacustrine basins in compressional settings are an important type of petroliferous basin, and the study of the characteristics of hydrocarbon accumulation in such basins is of great significance. This synthesis paper takes the Mesozoic Ordos Basin (central China) as a case study to establish lateral and vertical hydrocarbon accumulation patterns in this basin type, and highlights how facies and fluid potential control hydrocarbon accumulation in such basins. Based on systematic analyses of the Mesozoic source rocks, sedimentary facies, migration and accumulation patterns, and characteristics of the oil reservoirs, the hydrocarbon accumulation characteristics in the Mesozoic Ordos Basin are discussed. The analysis indicates that sedimentary facies controlled the characteristics and distribution of hydrocarbon source rocks and reservoirs, while diagenetic facies controlled the quality and distribution of the reservoirs. Excess pressure and fluid potential controlled hydrocarbon migration directions and paths, whereas facies and potential controlled the locations of oil accumulations and traps. It is concluded that source rocks controlled oil-bearing regions, sedimentary facies controlled oil-bearing plays, and fluid potential controlled the locations of accumulations. For shallow intervals, because fluid migration is mainly controlled by buoyancy, paleotopographic highs played an important role in controlling hydrocarbon accumulations. For deep layers (Chang 7 to Chang 10 members), since buoyancy is less than the capillary pressure, excess pressure caused by the undercompaction of mudstone and hydrocarbon generation at depth provides the driving force for lateral and vertical migration of oil, and becomes the main migration force. The reservoir accumulation characteristics differ laterally between regions of the basin; at the periphery of the basin, reservoir units are stacked in a step-wise manner, whereas at the center of the basin, multiple reservoir intervals are vertically stacked in the form of multistorey accumulations. Vertically, layers with different burial depths have different accumulation characteristics; the paleotopography controlled hydrocarbon accumulation in shallow intervals; instead excess pressure, fluid potential, and paleotopography controlled accumulation in deep intervals. This understanding could be used to inform prospecting in other large-scale lacustrine petroliferous basins in compressional settings such as the Eocene Green River Basin in the U.S.A. and the Middle Triassic Gunnedah Basin in Australia. Image 1 • Accumulation patterns in large-scale lacustrine petroliferous basins are defined. • Controls on oil accumulation by facies and potential in Ordos Basin are explored. • Patterns of hydrocarbon accumulation vary vertically and laterally. [ABSTRACT FROM AUTHOR]

The Dongying depression is an important oil-producing area in northeastern China, where the Paleogene Shahejie Formation is the main oil-bearing feature. Although petroleum migration and accumulation in the Dongying depression have been extensively studied, the charging history is still unclear. This paper defines the timeframe of petroleum migration on the basis of a comprehensive investigation of fluid inclusions coupled with basin modeling. According to the petrography and microthermometry of the fluid inclusions, types of fluid inclusion with low-peak-range distributions of the homogenization temperature (T h) (85–95 °C for the Niuzhuang sag and 90–105 °C for the Lijin sag) and high-peak-range T h distributions (105–120 °C for the Niuzhuang sag and 115–130 °C for the Lijin sag) were identified. By recovering the burial and thermal histories of Niuzhuang and Lijin sags with pressure–volume–temperature–composition simulation and one-dimensional basin modeling, it can be inferred that the trapping pressures of two types of hydrocarbon inclusions were higher than the corresponding paleopressure. (42.4 and 42.0 MPa, respectively), indicating rapid hydrocarbon charging resulting from abnormally high pressure. Two hydrocarbon charging events associated with the regional tectonic evolution of the Dongying depression, namely, continuous deposition and tectonics in the Paleogene Dongying Formation (Ed) and rapid deposition and tectonics in the Paleogene Minghuazhen Formation (Em), were inferred. The direction of oil charging was traced from the center to the margin in the north, and from the center to the central fault in the southeastern part of the depression in general, as indicated by the molecular maturity parameters, which roughly coincided with the abnormal pressure. • The investigation of fluid inclusions showed two oil-charging episodes in Sha 3 reservoirs. • The basin modeling suggested each reservoir was charged during the Late Paleogene and Early Neogene respectively. • The oils are charged along with the central faults and from the center to the edge of the depression. [ABSTRACT FROM AUTHOR]

The study of transtensional faults is significantly important for analysing migration and accumulation of hydrocarbons in petroliferous basins. The purpose of this study is to present disparities in the temporal and spatial evolution of two boundary transtensional faults (northern Linshang Fault and southern Xiakou Fault) in the Huimin Depression by 2D structural restoration and quantitative calculations of fault activity. This paper also reveals the controls of transtensional faults on the migration and accumulation of hydrocarbons by considering the stress normal to the fault plane (P), the shale gouge ratio (SGR) of the fault zone, and models of migration pathways. The results show that the transtensional systems within the Huimin Depression were generated from the reactivation of basement faults under an oblique extensional stress field. The Linshang Fault linked two initially separated segments and then behaved as a single fault since the Ek period, whereas the Xiakou Fault retained significant three-segment growth properties during the Paleogene. During the hydrocarbon charging period, the weak activity and strong vertical sealing restricted the occurrence of vertical migration around the Xiakou Fault, while the relatively strong movement and weak vertical sealing resulted in multilayer hydrocarbon accumulations around the Linshang Fault. Meanwhile, the vertically closed fault with high SGR (>0.6) acted as barriers and trapped hydrocarbons on the lateral migration pathways, whereas the vertically closed fault with low SGR (<0.6) served as conduits for further lateral migration into structurally higher positions. The discovered hydrocarbons are concentrated around transtensional fault systems, and the divergent E-W-striking brush-shaped secondary faults trapped abundant hydrocarbons within the hanging wall, demonstrating the important controls of the transtensional faults on the migration and accumulation of hydrocarbons in the Huimin Depression. • Movement characteristics and evolution process of the transtensional fault systems. • Activity intensity and vertical sealing during the charging period control the vertical hydrocarbon migration. • The lateral sealing variations during fault evolution control the lateral hydrocarbon migration and accumulation. • Closed brush-shaped secondary faults in the transtensional fault system are beneficial for trapping hydrocarbon. [ABSTRACT FROM AUTHOR]

The Chengzikou Uplift (CZKU) is a second-order structure surrounded by several hydrocarbon generative kitchens in the Bohai Bay Basin. However, six recently drilled wells on the CZKU failed to prove hydrocarbon occurrences, which causes confusion for the understanding of hydrocarbon migration and accumulation on the CZKU. Mainly based on the seismic database, this paper attempted to determine the hydrocarbon migration pathways and enrichment mechanisms on the CZKU. The results show that the lateral and vertical hydrocarbon migration seems to take place through a stepped pathway system consisting of permeable layers within unconformities, permeable carrier beds, and faults. Through a simple 3D modeling considering topography changes only, the hydrocarbons tend to migrate from the northern sags to the southern slope and uplift with parallel mainstreams and accumulate with convergent mainstreams. The potential hydrocarbon traps mainly include stratigraphic, structural, and structural-lithologic traps, most of which have been confirmed by previous explorations. Subsequently, two preliminary interpretations for the dry well on the CZKU are made: the first is hydrocarbons mainly accumulated in the Paleogene stratigraphic (onlapping) traps within the sag and slope area, conducting no further migration to the uplift; the other is hydrocarbons may migrate to the slope and uplift but were trapped in structural-lithologic traps associated with faults beyond the area of the dry wells. Moreover, favorable hydrocarbon accumulation targets are predicted to reduce exploration risk. • Hydrocarbons migrate via a stepped pathway system from sag to slope and uplift. • Preliminary interpretations for the dry holes on the uplift are made. • Hydrocarbon migration and accumulation mechanisms are discussed by analogy with adjacent slope belts. • Paleogene and Neogene exploration targets are predicted respectively. [ABSTRACT FROM AUTHOR]

Hydrocarbon saturation is an important petrophysical parameter in reservoir evaluation and reserve calculation. Dielectric dispersion logs have been widely used to estimate the hydrocarbon saturation, especially in high salinity shale formations. However, there is still room to improve the accuracy of interpretation of dielectric dispersion logs. In this paper, we used two interpretation models combined four dielectric permittivity and four conductivity logs measured by Array Dielectric Tool (ADT) at four frequencies to predict the hydrocarbon saturation in shale oil reservoirs, Triassic Yanchang Formation, Ordos Basin, China. The logs measured at the highest frequency are interpreted by the Complex Refractive Index (CRIM) model. And the other three frequencies measured logs are processed by the shaly sandstone (SHSD) model. Based on the two models, simulated annealing algorithm is selected to calculate water saturation and rock textual parameter, the dispersive phase fraction, and water salinity. Besides, accurate porosity, dielectric permittivity of rock matrix, and temperature are input information to the proposed method. The proposed method is applied to shale oil reservoirs of Triassic Yanchang Formation in two wells. The effectiveness and reliability of proposed model is verified by synthetic log responses. The mean relative error between synthetic and field logs is small. The predicted hydrocarbon saturation is consistent with core data, and its variation is consistent with characteristics of NMR T 2 distributions, verifying the accuracy and reliability of proposed method and inversion results. Our estimated hydrocarbon saturation of the two wells is about 30%, showing a good oil generation potential of the studied shale oil reservoirs. [ABSTRACT FROM AUTHOR]