下扬子区下古生界油气有利勘探区带探讨

下扬子区下古生界具有良好的油气地质条件,具备形成大型油气藏的物质基础,但一直未获得油气勘探的突破。本文通过地质、地球物理综合解释,结合部分地质露头、钻井资料及上扬子勘探成果,重点对下扬子区下古生界构造地质特征与油气地质条件等开展了综合分析研究。从构造沉积充填角度将下扬子区分为4个二级构造单元,中部地区的无锡-黄山断隆带构造相对稳定,分析认为其西北部的无锡-黄桥低褶带为油气勘探的有利区带,具有形成下古生界弱改造型油气藏的勘探前景。     

海洋沉积物孔隙水中阴阳离子含量的离子色谱法分析方法

分别采用Metrosep A Supp4-250型阴离子柱和Metrosep C 2-150型阳离子柱,以1.8 mmol/L Na2CO3 1.7 mmol/L NaHCO3和4 mmol/L酒石酸 0.75 mmol/L吡啶二羧酸为阴阳离子淋洗液,用离子色谱仪来测定海洋沉积物孔隙水中阴离子Cl-、Br-和SO42-浓度和阳离子Na 、NH4 、K 、Ca2 、Mg2 的浓度。特别是针对高Cl-和高Na 背景下Br-和NH4 的测定做了专门分析,得到了较理想的结果,建立了一套离子色谱法测定海洋沉积物孔隙水中常见的阴阳离子含量的实验方法。     

蒙特卡罗法在天然气水合物资源量计算中的应用

天然气水合物甲烷资源量的估算是天然气水合物研究中的热点问题。运用体积法计算含水合物沉积物中的甲烷资源量时,存在参数赋值不确定的问题,从而影响了计算结果的可信度。采用蒙特卡罗法,通过计算样本的频率可以较好地评价和描述计算结果的信度,弥补体积法的不足。对采用蒙特卡罗法估算甲烷资源量的原理进行了分析和探讨,并以麦肯齐三角洲和南海海域水合物为例,计算了水合物赋存区的甲烷资源量。     

Dissolved inorganic carbon (DIC) and its carbon isotopic composition in sediment pore waters from the Shenhu area,northern South China Sea

The Shenhu area is one of the most favorable places for the occurrence of gas hydrates in the northern continental slope of the South China Sea. Pore water samples were collected in two piston cores (SH-A and SH-B) from this area, and the concentrations of sulfate and dissolved inorganic carbon (DIC) and its carbon isotopic composition were measured. The data revealed large DIC variations and very negative δ ¹³C-DIC values. Two reaction zones, 0–3 mbsf and below 3 mbsf, are identified in the sediment system. At site SH-A, the upper zone (0–3 mbsf) shows relatively constant sulfate and DIC concentrations and δ ¹³C-DIC values, possibly due to bioturbation and fluid advection. The lower zone (below 3 mbsf) displays good linear gradients for sulfate and DIC concentrations, and δ ¹³C-DIC values. At site SH-B, both zones show linear gradients, but the decreasing gradients for δ ¹³C-DIC and SO₄ ²⁻ in the lower zone below 3 mbsf are greater than those from the upper zone, 0–3 mbsf. The calculated sulfate-methane interface (SMI) depths of the two cores are 10.0 m and 11.1 m, respectively. The depth profiles of both DIC and δ ¹³C-DIC showed similar characteristics as those in other gas hydrate locations in the world oceans, such as the Blake Ridge. Overall, our results indicate an anaerobic methane oxidation (AMO) process in the sediments with large methane flux from depth in the studied area, which might be linked to the formation of gas hydrates in this area.     

天然气水合物的声学探测模拟实验

在人工岩心中进行天然气水合物的生成和分解实验,同时获取了体系的温度、压力、声学特性(Vp和Vs、幅度和频率)及含水量等参数。经研究发现,温压法、超声探测法和TDR探测法都能灵敏探测沉积物中天然气水合物的形成和分解过程。分析认为,本次实验中水合物形成速率过快,只能宏观研究水合物对沉积物声学特性的影响,建议采用长岩心进一步研究沉积物中水合物的声学特性。     

南海东沙东北部甲烷缺氧氧化作用的生物标志化合物及其碳同位素组成

南海东沙东北部碳酸盐岩和泥质沉积物中的生物标志化合物组合及其碳同位素组成分析表明,研究区内甲烷缺氧氧化作用(anaerobic oxidation of methane-AOM)发育.研究区内碳酸盐岩中含丰富的AOM标志化合物,2,6,11,15-四甲基十六烷(Crocetane-Cr.)、2,6,10,15,19-五甲基番茄烷(Pentamethylicosane-PMI)和2,6,10,15,19,23-六甲基二十四烷(Squalane-Sq角鲨烷)的13C亏损强烈(δ13C值介于-74.2‰~-119.0‰PDB之间),表明碳酸盐岩形成于AOM,同时反映该研究区曾发生过强烈、持续的富CH₄流体释放活动.柱状泥质沉积物中,AOM生物标志化合物在硫酸岩-甲烷过渡带(SMI-Sulfate-Methane Interface)边界附近相对丰度高,SMI之上样品中含量低,或未检出,表明现代环境在SMI附近有大量嗜甲烷微生物生长,使得深部上升的甲烷被大量消耗,很少有甲烷逸出海底.AOM生物标志化合物可用来指示SMI边界.不同站位、不同岩性AOM生物标志化合物组成(包括碳同位素组成)的差异反映了嗜甲烷古细菌组成的不同.     

天然气水合物赋存区甲烷渗漏活动的地球化学响应特征

综述了天然气水合物赋存区甲烷渗漏活动的地球化学响应指标的研究进展,分析了应用单一指标识别甲烷渗漏活动各自所存在的问题,包括浅表层沉积物孔隙水中CH_4、SO_4~(2–)、Cl~–等离子浓度随深度的变化;浅层沉积物全岩W_(TOC)(W表示质量分数,TOC表示总有机碳)和W_(TS)(TS表示总硫)之间的相关性及比值;自生碳酸盐岩δ~(13)C和δ~(18)O;自生矿物重晶石、黄铁矿、自生石膏的δ~(34)S;有孔虫壳体和生物标志化合物的δ~(13)C等。结果表明孔隙水中的CH_4、SO4_~(2–)浓度及溶解无机碳的碳同位素组成可以用来识别目前正在发生的甲烷渗漏活动;而沉积物中的WTS、自生矿物的δ~(34)S、钡含量及其异常峰值和生物标志化合物的δ~(13)C等指标的联合使用可以更真实准确地反映地质历史时期天然气水合物赋存区的甲烷渗漏活动。因此,在实际研究过程中,可将孔隙水和沉积物两种介质的多种指标相结合。随着非传统稳定同位素(Fe、Ca、Mg等)和沉积物氧化还原敏感元素(Mo、V、U等)等研究的发展,甲烷渗漏活动地球化学响应指标的研究也将得到拓展,而多种地球化学指标的联合使用将为天然气水合物勘探及其形成分解过程识别研究提供重要的科学依据。     

Pore characterization of organic-rich Lower Cambrian shales in Qiannan Depression of Guizhou Province,Southwestern China

Nine organic-rich shale samples of Lower Cambrian black shales were collected from a recently drilled well in the Qiannan Depression, Guizhou Province where they are widely distributed with shallower burial depth than in Sichuan Basin, and their geochemistry and pore characterization were investigated. The results show that the Lower Cambrian shales in Qiannan Depression are organic rich with TOC content ranging from 2.81% to 12.9%, thermally overmature with equivalent vitrinite reflectance values in the range of 2.92–3.25%, and clay contents are high and range from 32.4% to 53.2%. The samples have a total helium porosity ranging from 2.46% to 4.13% and total surface area in the range of 9.08–37.19 m²/g. The estimated porosity in organic matters (defined as the ratio of organic pores to the volume of total organic matters) based on the plot of TOC vs helium porosity is about 10% for the Lower Cambrian shales in Qiannan Depression and is far lower than that of the Lower Silurian shales (36%) in and around Sichan Basin. This indicates that either the organic pores in the Lower Cambrian shale samples have been more severely compacted than or they did not develop organic pores as abundantly as the Lower Silurian shales. Our studies also reveal that the micropore volumes determined by Dubinin–Radushkevich (DR) equation is usually overestimated and this overestimation is closely related to the non-micropore surface area of shales (i.e. the surface area of meso- and macro-pores). However, the modified BET equation can remove this overestimation and be conveniently used to evaluate the micropore volumes/surface area and the non-micropore surface areas of micropore-rich shales.     

Paragenesis of fluids under evaporates in the Volga-Ural Basin

To unravel the mystery of the relationship between evaporates, Ca–Cl brines and accumulations of oil and N₂ in the basins of ancient cratons, their N₂, CH₄ and He concentration ratios, as well as the isotopic composition (δ¹⁵N, δ¹³C and ³He/⁴He) were compared within the Volga-Ural basin. The study allowed subsalt fluids from Volga-Ural Basin to divide into two genetic groups. The first one is found within the basin's platform area. It includes Ca–Cl brines, high-viscosity heavy oil, bitumen and N₂, which has concentrations higher than that of CH₄ and positive values of δ¹⁵N. The second one is tied to the edge of the platform, the Ural Foredeep and Peri-Caspian Depression. In this group, only the oil and gas reservoirs, which have more CH₄ than N₂, and possibly negative values of δ¹⁵N, were discovered. Interaction of gas components in compared fluids indicates great role of degassing in the formation of their composition. It is suggested that the fluids of the first group (N₂ > CH₄) is what remains, and the second group (N₂ < CH₄) is what is disappears from the rocks during their metamorphism and degassing.     

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.