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Peng J.,Southwest Petroleum University | Zhang H.,Southwest Petroleum University | Lin X.,Key Laboratory of Sedimentary Basin and Oil and Gas Resources | Lin X.,Southwest Petroleum University
Carbonates and Evaporites | Year: 2017

Botryoidal dolostone (BD) developed extensively within the Neoproterozoic Upper Sinian Dengying Formation in the Hanyuan region, which is an important gas reservoir. Based on literature review, a study of their outcrop characteristics, petrology, microfabric, degree of order, and genesis reveal that BD mainly comprises botryoidal lumps (BL) originated from depositional-penecontemporaneous seawater and botryoidal and ctenoid cements or fillings. BL occurred in parallel beds during the depositional-syngenetic stage, including core and coating. The core consists of grapestone and thrombolite, which is dominated by muddy and microcrystalline high-magnesium calcite (HMC) resulting from marine deposition and micro-organism capturing and binding effects. The coating, classified as either thin or thick, is mainly isopachous fibrous aragonite (IFA) that formed during the depositional-syngenetic stage. Thin coatings formed in the turbulent sea bottom, while thicker ones formed in a relatively quiet sea bottom. Botryoidal and ctenoid cements and fillings compose IFA and HMC. IFA that includes marine phreatic zone deposition from the syngenetic-penecontemporaneous stage mainly occurs in the spaces between grains of BL and intraclast or on the top of them. The HMC that is the product from meteoric leaching in the penecontemporaneous stage and marine deposition occurs in the dissolved pores and fractures. During the process when BL and the botryoidal, ctenoid cements, or fillings formed, either abiogenetic or microbiogenic aragonite and HMC were mimetically dolomitized and preserved the primary texture and structure. BD was also reworked by the meteoric leaching in the penecontemporaneous and supergenous stages. © 2017 Springer-Verlag GmbH Germany


Ge X.-Y.,Key Laboratory of Sedimentary Basin and Oil and Gas Resources | Mou C.-L.,Key Laboratory of Sedimentary Basin and Oil and Gas Resources | Zhou K.,Key Laboratory of Sedimentary Basin and Oil and Gas Resources | Liang W.,Key Laboratory of Sedimentary Basin and Oil and Gas Resources
Geology in China | Year: 2013

Based on field survey, laboratory analysis of sedimentary strata and summarization of previous research results in Hunan Province, the authors divided the Ordovician tectonic and sedimentary evolution into four stages, i.e., rimmed carbonate platform-shelf-deep water basin in the Early Ordovician, carbonate ramp-shelfdeep basin in the Middle Ordovician, carbonate ramp-shelf-deep water basin-shelf margin at the early age of Late Ordovician, and confined shallow marine -deep water basin -shelf margin in the late period of the Late Ordovician. The northwestern Hunan in Yangtze craton experienced the evolution from the rimmed carbonate platform to carbonate ramp, and finally became a confined shallow sea, with the black shale gradually replacing carbonates in lithology. The central and southern Hunan located at the edge of the craton and the Cathaysia Block was always in a elastic shallow marine environment, and the center of the basin migrated constantly from southeast to northwest.


Xiong X.-H.,Chengdu Institute of Geology and Mineral Resources | Xiong X.-H.,Key Laboratory of Sedimentary Basin and Oil and Gas Resources | Wang J.,Chengdu Institute of Geology and Mineral Resources | Wang J.,Key Laboratory of Sedimentary Basin and Oil and Gas Resources | And 10 more authors.
Meitan Xuebao/Journal of the China Coal Society | Year: 2016

To understand the sedimentary environment evolution, shale gas prospect and their relationship of Nanmingshui Fm dark mudstone from Shaerbulake Region, Fuyun Basin, the analysis on inorganic, organic geochemistry and mineralogy were performed. It shows that, influenced by large rivers import, water desalination occurred during the sedimentation. Water openness decreased later, and the salinity re-increased gradually. It was warm and moist generally, then became warmer and drier in middle-late stage during Nanmingshui Fm sedimentation. There was a deep-shallow-deep change in water depth upward Nnmingshui Fm. Reducing condition occurred during dark mudstone sedimentation, but it weakened upward Nanmingshui Fm. The organic matter is dominated by type Ⅲ with a few type II2, and its evolution is in a high-over maturation. The second member of Nanmingshui Fm bears highest biological production and total organic matter (TOC: 0.42%-1.11%). Mineral composition is dominated by clay and quartz, especially in the dark mudstone from the second member (clay: 32%-49%; quartz: 33%-41%; illite in clay: 61%-77%), which have good factors for shale gas development. The study shows that brackish water with salinity lean to salt water, lack of large river import, stable sedimentary environment etc. are more beneficial to the development of gas-producing shale. © 2016, Editorial Office of Journal of China Coal Society. All right reserved.


Wang L.,Southwest Petroleum University | Wang L.,Key Laboratory of Sedimentary Basin and Oil and Gas Resources | Mao Z.-Q.,China University of Petroleum - Beijing | Sun Z.-C.,Petrochina | And 3 more authors.
Chinese Journal of Geophysics (Acta Geophysica Sinica) | Year: 2015

The fluid permeability describes the flow characteristics of rock, which is an important parameter in the evaluation of reservoirs and prediction of oil and gas production. The fluid permeability can be measured when brine solution flow in pores and has physical and chemical effects with clays which adhere to or coat the grains. The measurement conditions of fluid permeability are similar to the actual conditions of shale sandstone reservoirs, so this parameter is considered to be better expression of the flow characteristics of shale sandstone reservoirs. However, there are few evaluation models of fluid permeability reported, and the existing models cannot reveal the relationship between fluid permeability and salinity of solution. To address this issue, this paper presents a model for fluid permeability calculation. In this study, based on the assumption that the shaly sand can be simplified as a capillary tubes model, a expression of fluid permeability in terms of the surface area, tortuosity of throat, total porosity, and bound water porosity of clay is deduced. In addition, according to the physics volume model, the relationship of bound water porosity of clay to cation exchange capacity and salinity of solution is derived. Finally, by means of introducing the bound water porosity of clay to the expression of fluid permeability, a theoretical model of fluid permeability in terms of total porosity, cation exchange capacity, salinity of solution, surface area, and tortuosity of throat is deduced. The theoretical model and two sets of experimental data of fluid permeability show that the fluid permeability decreases with the increasing cation exchange capacity, and increases with the growing salinity of solution. However, in the application of the model of fluid permeability, it is difficult to calculate the parameters of the surface area and tortuosity of throat. So the application of the theoretical model to calculate the fluid permeability is limited. Based on the analysis of the models of fluid permeability and air permeability, a transformation model of fluid permeability and air permeability is established. Then, with the help of the transformation model, a new method for calculating fluid permeability is suggested. In order to verify the accuracy of the transformation model of fluid permeability and air permeability, two sets of experimental data are used to calculate fluid permeability. Comparison of the calculated fluid permeability and core measured fluid permeability shows that the calculated fluid permeability matches fairly well with core measured results, which indicates that the transformation model in this study is credible. ©, 2015, Science Press. All right reserved.


Wang L.,Southwest Petroleum University | Wang L.,Key Laboratory of Sedimentary Basin and Oil and Gas Resources | Mao Z.-Q.,China University of Petroleum - Beijing | Sun Z.-C.,China National Petroleum Corporation | And 4 more authors.
Journal of Geophysics and Engineering | Year: 2015

Cation exchange capacity (Qv) is a key parameter in resistivity-based water saturation models of shaly sand reservoirs, and the accuracy of Qv calculation is crucial to the prediction of saturations of oil and gas. In this study, a theoretical expression of Qv in terms of shaly sand permeability (Kshaly-sand), total porosity (φt), and salinity of formation water (S) is deduced based on the capillary tube model and the physics volume model. Meanwhile, the classical Schlumberger-Doll research (SDR) model has been introduced to estimate Kshaly-sand. On this basis, a novel technique to estimate Qv from nuclear magnetic resonance (NMR) logs is proposed, and the corresponding model is also established, whose model parameters are calibrated by laboratory Qv and NMR measurements of 15 core samples from the Toutunhe formation of the Junggar Basin, northwest China. Based on the experimental data sets, this technique can be extended to reservoir conditions to estimate continuous Qv along the intervals. The processing results of field examples illustrate that the Qv calculated from field NMR logs are consistent with the analyzed results, with the absolute errors within the scope of ±0.1 mmol cm-3 for the majority of core samples. © 2015 Sinopec Geophysical Research Institute.

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