pT-effects of Pleistocene glacial periods on permafrost,gas hydrate stability zones and reservoir of the Mittelplate oil field,northern Germany

During the past two million years low surface temperatures as well as episodically advancing ice sheets from Scandinavia acted on the subsurface pT-regime of northern Germany. Their likely effects on the petroleum system of Schleswig-Holstein were investigated. For the entire Quaternary mean annual ground temperature (MAGT) was reconstructed at a resolution of 1000 years by calibrating oxygen isotope records from ODP-site 659 to the climate of northern Germany of the past 120 kyr. The resulting MAGT trend served as input to an ice sheet model and a permafrost model along a 2D section crossing the petroleum bearing south-western part of Schleswig-Holstein. Here advances and retreats of the Scandinavian ice sheet during Saalian and Elsterian glaciation Stages were reconstructed. Maximum ice thicknesses of up to 1700 m and up to 20 periods of regional permafrost in northern Germany were reconstructed for the past 1.25 million years. Based on a basal heat flow of 50 mW/m² permafrost thicknesses exceeded 100 m during most of these periods, temporarily extending down to depths of more than 300 m. Favourable surface temperatures and long durations of cold periods provided favourable conditions for onshore gas hydrate stability zones at Mittelplate. Implementing these glacial dynamics into 2D basin modelling (PetroMod, IES, Aachen, Germany) of the Mittelplate oil field reveals five phases of gas hydrate stability at depths down to 750 m. The latest of these events occurred during the Weichselian about 20 kyr ago. The effect of the ice sheets on pore pressure in the subsurface strongly depends on the hydraulic boundary conditions at the ice base (e.g. frozen vs. temperate ice sheet base). Excess pore pressure in the reservoir of more than 10 MPa during ice overriding is possible and probable. The calculated temperature effect of the Pleistocene cooling on the Mittelplate reservoir is in the range of 3–7 °C. Even today temperature in the reservoir is still lowered by about 4 °C in comparison to pre-Pleistocene times. Despite the fact that a significant influence of glacial effects on petroleum generation can be ruled out at Mittelplate, we state that pT-effects in reservoirs related to glacial processes in formerly glaciated areas have been underestimated in the past.     

油气田开发中油气藏地质成因分析

本文从油气藏地质成因分析的基础资料入手,总结该项研究的主要内容包括:构造、储层和油气水分布特征等3方面.结合自身科研实践,认为油气藏地质成因分析方法主要包括:野外露头和现代沉积考察、岩心观察描述、显微镜下薄片观察鉴定、地球物理解释预测、地质统计学分析、分析测试、各种物理模拟和数值模拟、油气藏动态监测和生产动态等,并阐述了不同研究方法的优缺点.目前油气藏地质成因分析存在的主要问题包括:对油气藏地质成因分析重视程度不够、研究方法偏定性、地质成因分析和油气藏表征结合不紧密、油气藏表征精度制约了地质成因分析的准确度、油气藏地质成因分析综合性不强、特殊类型油气藏地质成因分析还存在诸多难题等.本文指出了该研究未来发展方向.主要包括:依靠油气藏地质成因分析解决油气田开发中的难题、通过各种模拟方法提高油气藏地质成因分析定量化水平、加强地质成因分析以提高油气藏表征水平、利用油气藏表征促进地质成因分析进步、拓展油气藏地质成因分析在油气田开发中应用的领域、特殊类型油气藏地质成因分析等.     

A new approach to assessing the water footprint of hydroelectric power based on allocation of water footprints among reservoir ecosystem services

Hydroelectric power is an important energy source to meet the growing demand for energy, and large amounts of water are consumed to generate this energy. Previous studies often assumed that the water footprint of hydroelectric power equaled the reservoir’s water footprint, but failed to allocate the reservoir water footprint among the many beneficiaries; dealing with this allocation remains a challenge. In this study, we developed a new approach to quantify the water footprint of hydroelectric power (WF_h) by separating it from the reservoir water footprint (WF) using an allocation coefficient (η_h) based on the ratio of the benefits from hydroelectric power to the total ecosystem service benefits. We used this approach in a case study of the Three Gorges Reservoir, the world’s largest reservoir, which provides multiple ecosystem services. We found large differences between the WF_h and the water footprint of per unit of hydroelectric production (PWF_h) calculated using η_h and those calculated without this factor. From 2003 to 2012, η_h decreased sharply (from 0.76 in 2005 to 0.41 in 2012), which was due to the fact that large increases in the value of non-energy ecosystem services, and particularly flood control. In 2009, flood control replaced hydroelectricity as the largest ecosystem service of water from the Three Gorges Reservoir. Using our approach, WF_h and PWF_h averaged 331.0 × 10⁶ m³ and 1.5 m³ GJ⁻¹, respectively. However, these values would almost double without allocating water footprints among different reservoir ecosystem services. Thus, previous studies have overestimated the WF_h and PWF_h of reservoirs, especially for reservoirs that serve multiple purposes. Thus, the allocation coefficient should not be ignored when calculating the WF of a product or service.     

金沙江下游梯级水库运行后三峡水库高洪水期入库水沙特性

泥沙淤积问题直接影响着三峡水库的使用寿命及综合效益的发挥,研究其入库水沙特性对于解决水库泥沙淤积问题具有重要意义。根据水文站实测数据,分析了三峡水库入库水沙输移特性及来源组成变化,重点研究了金沙江下游梯级水库运行后的三峡水库高洪水期入库水沙特性。结果表明:2003—2021年,三峡水库入库泥沙集中于汛期的高洪水期,2013年以后该现象更为显著,泥沙来源也由金沙江为主转变为嘉陵江为主。寸滩站洪峰流量高于50000 m³/s的高洪水期三峡入库沙量显著大于30000～50000 m³/s区间的高洪水期,三峡水库泥沙调度关键在于上游发生编号洪水期间。三峡水库上游沱江或嘉陵江等支流发生流域性大洪水时,易引起高洪水期入库水沙出现“小水大沙”的特点。金沙江下游梯级水库运行后,三峡水库高洪水期入库泥沙大幅减少,中小洪水调度期间泥沙淤积量也大幅减小。研究结果可为三峡水库的泥沙精细化调度和长期高效使用提供基础数据支撑。     

3-D internal architecture of methane hydrate-bearing turbidite channels in the eastern Nankai Trough, Japan

The reservoir architecture of methane hydrate (MH) bearing turbidite channels in the eastern Nankai Trough, offshore Japan is evaluated using a combination of 3-D seismic and well data. On the 3-D seismic section, the MH-bearing turbidite channels correspond to complex patterns of strong seismic reflectors, which show the 3-D internal architecture of the channel complex. A seismic-sequence stratigraphic analysis reveals that the channel complex can be roughly classified into three different stages of depositional sequence (upper, middle, and lower). Each depositional sequence results in a different depositional system that primarily controls the reservoir architecture of the turbidite channels. To construct a 3-D facies model, the stacking patterns of the turbidite channels are interpreted, and the reservoir heterogeneities of MH-bearing sediments are discussed. The identified channels at the upper sequence around the β1 well exhibit low-sinuosity channels consisting of various channel widths that range from tens to several hundreds of meters. Paleo-current flow directions of the turbidite channels are typically oriented along the north-northeast-to-south-southwest direction. High-amplitude patterns were identified above the channels along the north-to-south and north-northeast-to-south-southeast directions. These roughly coincide with the paleo-current flow of the turbidite channels. An interval velocity using high-density velocity analysis shows that velocity anomalies (>2000 m/s) are found on the northeastern side of the turbidite channels. The depositional stage of the northeastern side of the turbidite channels exhibits slightly older sediment stages than the depositional stages of the remaining channels. Hence, the velocity anomalies of the northeastern side of the channels are related to the different stages of sediment supply, and this may lead to the different reservoir architectures of the turbidite channels.     

Provenance of deep-water reservoir sandstones from the Jubarte oil field,Campos Basin,Eastern Brazilian Margin

The provenance of the Maastrichtian deep-water reservoir sandstones from the Jubarte oil field (Campos Basin, eastern Brazil), was studied using an integrated approach that included quantitative petrography, conventional heavy mineral analysis, garnet mineral chemistry and zircon geochronology. The reservoirs are predominantly coarse, poorly-sorted sandstones with feldspathic composition derived from uplifted basement terrains. The fourth- and fifth-order depositional sequences analyzed show no major variations in composition or in provenance through time. However, variations in apatite:tourmaline presents potential to be used as a parameter for sandstone correlation within the field. The composition of heavy minerals indicates derivation from high temperature and low-to-medium pressure aluminous metapelitic rocks, from granites and subordinate mafic rocks, derived from the Cabo Frio Tectonic Domain and the Oriental terrain of Ribeira orogen, characterizing a supply route from SW to NE. The low ZTR index, as well as the absence of low-grade stable heavy minerals and of metasedimentary rock fragments, suggest that by the end of Cretaceous all supracrustal, low-grade terrains had already been totally eroded, and that plutonic, infracrustal rocks were exposed, similarly to the present situation.     

Reservoir origin and characterization of gas pools in intrusive rocks of the Yingcheng Formation,Songliao Basin,NE China

In 2013, the first discovery of gas pools in well LS 208 in intrusive rocks of the Songliao Basin (SB), NE China was made in the 2nd member of the Yingcheng Formation in the Yingtai rift depression, proving that intrusive rocks of the SB have the potential for gas exploration. However, the mechanisms behind the origin of reservoirs in intrusive rocks need to be identified for effective gas exploration. The gas pool in intrusive rocks can be characterized as a low-abundance, high-temperature, normal-pressure, methane-rich, and lithologic pool based on integrated coring, logging, seismic, and oil test methods. The intrusive rocks show primary and secondary porosities, such as shrinkage fractures (SF), spongy pores (SP), secondary sieve pores (SSP), and tectonic fractures (TF). The reservoir is of the fracture–pore type with low porosity and permeability. A capillary pressure curve for mercury intrusion indicates small pore-throat size, negative skewness, medium–high displacement pressure, and middle–low mercury saturation. The development of fractures was found to be related to the quenching effects of emplacement and tectonic inversion during the middle–late Campanian. SP and SSP formed during two phases. The first phase occurred during emplacement of the intrusive rock in the late Albian, when the intrusions underwent alteration by organic acids. The second phase occurred between the early Cenomanian and middle Campanian, when the intrusions underwent alteration by carbonic acid. The SF formed prior to oil charging, the SSP + SP formed during oil charging, and the TF formed during the middle–late Campanian and promoted the distribution of gas pools throughout the reservoir. The intrusive rocks in the SB and the adjacent basins were emplaced in the mudstone and coal units, and have great potential for gas exploration.     

Kilometer-scale fault-related thermal anomalies in tight gas sandstones

Upper Carboniferous sandstones make one of the most important tight gas reservoirs in Central Europe. This study integrates a variety of geothermometers (chlorite thermometry, fluid inclusion microthermometry and vitrinite reflection measurements) to characterize a thermal anomaly in a reservoir outcrop analog (Piesberg quarry, Lower Saxony Basin), which is assumed responsible for high temperatures of circa 300 °C, deteriorating reservoir quality entirely. The tight gas siliciclastics were overprinted with temperatures approximately 90–120 °C higher compared to outcropping rocks of a similar stratigraphic position some 15 km to the west. The local temperature increase can be explained by circulating hydrothermal fluids along the fault damage zone of a large NNW-SSE striking fault with a displacement of up to 600 m in the east of the quarry, laterally heating up the entire exposed tight gas sandstones. The km-scale lateral extent of this fault-bound thermal anomaly is evidenced by vitrinite reflectance measurements of meta-anthracite coals (VR_rot ∼ 4.66) and the temperature-related diagenetic overprint. Data suggest that this thermal event and the associated highest coalification was reached prior to peak subsidence during Late Jurassic rifting (162 Ma) based on K-Ar dating of the <2 μm fraction of the tight gas sandstones. Associated stable isotope data from fluid inclusions, hosted in a first fracture filling quartz generation (T ∼ 250 °C) close to lithostatic fluid pressure (P ∼ 1000 bars), together with authigenic chlorite growth in mineralized extension fractures, demonstrate that coalification was not subject to significant changes during ongoing burial. This is further evidenced by the biaxial reflectance anisotropy of meta-anthracite coals. A second event of quartz vein formation occurred at lower temperatures (T ∼ 180 °C) and lower (hydrostatic) pressure conditions (P ∼ 400 bars) and can be related to basin inversion. This second quartz generation might be associated with a second event of illite growth and K-Ar ages of 96.5–106.7 Ma derived from the <0.2 μm fraction of the tight gas sandstones.This study demonstrates the exploration risk of fault-bound thermal anomalies by deteriorating entirely the reservoir quality of tight gas sandstones with respect to porosity and permeability due to the cementation with temperature-related authigenic cements. It documents that peak temperatures are not necessarily associated with peak subsidence. Consequently, these phenomena need to be considered in petroleum system models to avoid, for example, overestimates of burial depth and reservoir quality.     

New insights into the carbonate karstic fault system and reservoir formation in the Southern Tahe area of the Tarim Basin

As worldwide hydrocarbon exploration has extended from shallowly to deeply buried strata, reservoir quality has attracted substantial and persistent interest in petroleum geology. In particular, deeply buried strata (>5500 m) in the Tarim Basin have attracted considerable attention because carbonate reservoirs that have experienced fracture or dissolution have also been shown to demonstrate considerable hydrocarbon potential. Therefore, it is necessary to determine how these reservoirs are developed and distributed in detail from both scientific and practical standpoints.In this paper, we address this issue using a case study in the southern Tahe area, which is contained within the largest Palaeozoic marine oilfield in China. In the northern Tahe area, mega-paleokarst systems developed in the Ordovician strata; however, the reservoir quality in the southern part of the Tahe area is relatively poor because it is covered by insoluble formations during karstification. Observations of cores and analyses of images of well logging demonstrate that these reservoirs are dominated by caves, vugs and fractures that have developed near faults. We speculate that the faults penetrating insoluble formations represent the main dissolution passages that originally developed these karstic fault systems. Additionally, we analyse a series of outcrops, seismic data, and structures to characterize the spatial geometry of these major faults and their surrounding fractures in detail. Most of these are strike-slip faults, and their subsequent reservoirs can be divided into three categories based on their development, including dendritic, sandwich and slab reservoirs. Recent studies demonstrate that karstic fault reservoirs are most common traps in the study area. Although various types of carbonate karstic fault reservoirs are represented in this region, the dendritic karstic fault reservoir is the most hydrocarbon-rich.Guided by these initial results, 108 wells were drilled from 2013 to 2014, producing 485 thousand tons of oil and yielding success ratios greater than 89%. The average production of dendritic reservoirs is 37.4 tons per day (t/d), while those of sandwich and slab types are 20.2 t/d and 14.0 t/d, respectively. These results represent significant references for future hydrocarbon exploration and the development of similar deeply buried karstic fault reservoirs in the Tarim Basin and elsewhere.