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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]

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]

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]

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]

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]

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 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]