ALBERT

Description: 〈span〉〈div〉ABSTRACT〈/div〉The effects of reservoir heterogeneity on the development of submarine channel fields are still poorly understood because of lack of direct evidence for fluid flow. This study uses integrated well logs and three-dimensional seismic data from the Niger Delta Basin to characterize the previously undocumented spatial distribution of shale units and permeability contrasts within a submarine channel system. Combining these data with four-dimensional (4-D) seismic data facilitates the exploration of the controls of reservoir heterogeneity on fluid flow during development. The results show that the studied submarine channel system consists of multiple vertically stacked channel complex sets (CCSs) from CCS1 (oldest) to CCS5 (youngest), which are separated from each other by continuous shale barriers. The CCS2–CCS4, which are located in the stratigraphic middle of the channel system, are the main development layers because of their higher permeabilities and lower permeability contrasts. The 4-D seismic responses validate that the presence of shale barriers between vertically adjacent CCSs can hinder the flow of fluids between CCSs. Fluid flow between vertically adjacent CCSs barely occurs except in localized erosional locations where the sand fills of different CCSs are vertically connected. Each CCS consists of multiple individual channels, which can be separated by inclined shale baffles if they laterally migrate in one direction. As the 4-D seismic responses demonstrate, such inclined shale baffles can hinder fluid flow between adjacent individual channels and help to form multiple narrow flow paths in map view. The absence of inclined shale baffles also produces prominent permeability contrasts within each CCS, which are characterized by relatively high–permeability zones that are parallel to the channel axis. Comparison of this permeability distribution and the 4-D seismic responses shows that injected water preferentially sweeps along relatively high–permeability zones, which can help to form single wide flow paths with higher sweep efficiency or single narrow flow paths with lower sweep efficiency.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The uppermost Middle Triassic Leikoupo Formation in the western Sichuan Basin of China has recently been shown to host as much as 5.3 tcf (1.5 × 10〈sup〉12〈/sup〉 m〈sup〉3〈/sup〉) of natural gas resources. The reservoir rocks, composed mainly of microbially derived dolomudstone (e.g., thrombolites and stromatolites), are characterized by low porosity (〈8%) and permeability (〈0.001 to 10 md). The limestone is commonly tight and not of reservoir quality because of abundant meteoric calcite cementation, whereas the dolostone has various types of pores dominated by solution-enlarged pores and vugs, microbial framework pores, and micropores. Breccias are well developed in places, probably because of dissolution of underlying evaporites (e.g., anhydrite) by an influx of low-salinity fluids (e.g., freshwater and seawater) during an early burial stage. Early dolomitization created micropores in the dolomudstone, and subsequent diagenetic events were dominated by calcite, dolomite, quartz cementation, pyrite replacement, compaction, fracturing, and development of stylolites. Localized hydrothermal activity has been evidenced by high homogenization temperatures (∼160°C–200°C) obtained from fluid inclusions in fracture-filling cements. Bacterial sulfate reduction probably resulted in H〈sub〉2〈/sub〉S generation, pyrite precipitation, and solution-enlarged pore and vug formation, whereas part of the current H〈sub〉2〈/sub〉S in these reservoirs may have been sourced from thermochemical sulfate reduction or an underlying formation (e.g., the Feixiangguan Formation). Development of microfractures and associated micropores was probably the final diagenetic event, which improved pore interconnectivity. This study confirms the effect of diagenesis on the development of a microbial dolomudstone reservoir, which may be applicable to other similar microbial carbonate reservoirs elsewhere, for example, Middle Triassic sections of the Tethys region and offshore Brazil.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The impact of marine incursions during transgression (i.e., sea level rises and the shoreline moves landward) on the formation and quality of lacustrine source rocks is an important and contentious issue. In this study, we present a case study of the Paleogene Hetaoyuan Formation in the Biyang sag, Nanxiang Basin, eastern China. Paleontological, trace-element, and biomarker data indicate that the Hetaoyuan source rocks in this region were influenced by a marine incursion. The paleontological evidence indicates that the marine incursion resulted in the introduction of red and brown algae, which commonly inhabit marine environments. Trace-element analyses yielded representative evidence of marine incursion (e.g., equivalent boron content 〉300 ppm and B/Ga ratio 〉4.2). Biomarker evidence for marine incursion includes C〈sub〉26〈/sub〉/C〈sub〉25〈/sub〉 tricyclic terpanes ratios of 1:3, which is the threshold for distinguishing marine organic matter from lacustrine. Using the B/Ga ratio as a typical paleosalinity indicator, it was determined that the influence of marine incursion decreased from the Biye 1 to Cheng 2 to An 3006 wells, with the B/Ga ratio average decreasing from 7.51 to 6.81 to 3.73, respectively. With an increasing extent of marine incursion (e.g., distance landward, overall water depth, and marine–freshwater mixing), the primary productivity of organic matter increased, and the preservational environment became more reducing. These changes resulted in higher contents of organic matter (total organic carbon = 2–8 wt. %) and a more favorable type of organic matter for oil generation (kerogen type I–II), indicating that the marine incursion had a positive effect on the formation of source rocks. Therefore, the formation mechanism of high-quality source rocks in coastal lacustrine basins during high sea-level periods and associated resource potential might need to be reevaluated (e.g., the Campanian lower Neslen Formation along the margins of the Western Interior Seaway of North America and the terminal Oligocene–early Miocene in the fluvial Saldanha Bay at the southwestern tip of Africa). The results also provide useful data for regional oil and gas exploration.〈/span〉