Classification and Quantitative Characterization of Archean Metamorphic Buried Hill Reservoirs in the Bohai Sea.

Based on productivity test data and physical property test results from multiple wells, a classification scheme of Archean metamorphic buried hill reservoirs in the Bohai Sea is established by means of mathematical function fitting. By combining data from cores, casting thin sections, scanning electron microscopy, imaging logging, and high-pressure mercury injection and nitrogen adsorption tests, we clarified the reservoir composition and pore structure characteristics of different types of reservoirs are clarified. Furthermore, taking the BZ19-6 and 13-2 wells in the Archean metamorphic buried hills as an example, the development sites of different types of reservoirs are analyzed and the reservoir development model is established. The results show that the Archean metamorphic buried hill reservoirs in the Bohai Sea can be divided into three categories and six subcategories, including type I reservoirs with porosities greater than 8% or permeabilities greater than 1 × 10-3 µm2 and type II reservoirs with porosities of 5-8% or permeabilities in the range of 0.1-1 × 10-3 µm2. Reservoirs with porosities of 2-5% and permeabilities of 0.01-0.1 × 10-3 µm2 are type III reservoirs. Each type of reservoir can be further divided into a fracture-pore type and a fracture type according to the relative contribution of the porosity and permeability to the reservoir. From type I to type III, the dissolution degree and fracture development gradually weaken, the pore size gradually decreases, and the pore volume gradually decreases. The distribution of favorable reservoirs is comprehensively controlled by weathering and tectonic transformation. The presence of a weathered glutenite zone, weathered leaching zone, or weathered disintegration zone is favorable for the development of type I reservoirs in the weathering crust. In the inner part of the buried hill, the presence of a fracture zone with a thickness of more than 10 m or a dense fracture zone with a thickness of more than 40 m is favorable for the formation of type I reservoirs.

Semiquantitative microscopic pore characterizations of the metamorphic rock reservoir in the central paleo-uplift belt, Songliao Basin.

Currently, metamorphic rock is a common target for natural gas exploration, and reservoirs are the key factors restricting natural gas exploration and development in metamorphic rocks. The deep metamorphic rock gas reservoir in the central paleo-uplift of the northern Songliao Basin has good exploration and development potential. In this study, we use a combination of qualitative descriptions and quantitative analysis to comprehensively analyze the pore characteristics of the reservoir and explore the factors controlling the pore characteristics of the metamorphic rock reservoir in the central paleo-uplift belt of the Songliao Basin. The metamorphic rock reservoir in the central paleo-uplift belt contains three types of lithologies: chlorite schist, mica schist and mylonite, each with different protoliths and metamorphic histories. The results of high-pressure mercury intrusion and nitrogen adsorption indicate that the pore size distributions of the schist and mylonite differ. Compared with the mylonite, the schist has larger reservoir space, more heterogeneity, smaller pore size, larger specific surface area and larger adsorbed gas storage capacity. This paper also studies the formation process of the reservoir and divides it into four stages. Finally, this article discusses in detail the factors controlling the microscopic pore characteristics of metamorphic rock reservoirs in the central paleo-uplift belt; the metamorphic rock protolith is the most important controlling factor.

Reservoir quality and its controlling diagenetic factors in the Bentiu Formation, Northeastern Muglad Basin, Sudan.

The Abu Gabra and Bentiu formations are widely distributed within the interior Muglad Basin. Recently, much attention has been paid to study, evaluate and characterize the Abu Gabra Formation as a proven reservoir in Muglad Basin. However, few studies have been documented on the Bentiu Formation which is the main oil/gas reservoir within the basin. Therefore, 33 core samples of the Great Moga and Keyi oilfields (NE Muglad Basin) were selected to characterize the Bentiu Formation reservoir using sedimentological and petrophysical analyses. The aim of the study is to de-risk exploration activities and improve success rate. Compositional and textural analyses revealed two main facies groups: coarse to-medium grained sandstone (braided channel deposits) and fine grained sandstone (floodplain and crevasse splay channel deposits). The coarse to-medium grained sandstone has porosity and permeability values within the range of 19.6% to 32.0% and 1825.6 mD to 8358.0 mD respectively. On the other hand, the fine grained clay-rich facies displays poor reservoir quality as indicated by porosity and permeability ranging from 1.0 to 6.0% and 2.5 to 10.0 mD respectively. A number of varied processes were identified controlling the reservoir quality of the studies samples. Porosity and permeability were enhanced by the dissolution of feldspars and micas, while presence of detrital clays, kaolinite precipitation, iron oxides precipitation, siderite, quartz overgrowths and pyrite cement played negative role on the reservoir quality. Intensity of the observed quartz overgrowth increases with burial depth. At great depths, a variability in grain contact types are recorded suggesting conditions of moderate to-high compactions. Furthermore, scanning electron microscopy revealed presence of micropores which have the tendency of affecting the fluid flow properties in the Bentiu Formation sandstone. These evidences indicate that the Bentiu Formation petroleum reservoir quality is primarily inhibited by grain size, total clay content, compaction and cementation. Thus, special attention should be paid to these inhibiting factors to reduce risk in petroleum exploration within the area.

Response of a continental fault basin to the global OAE1a during the Aptian: Hongmiaozi Basin, Northeast China.

This paper presents new research on a lacustrine anoxic event (LAE). These data include stable carbon isotope (δ13Corg), pyrite sulfur isotope (δ34Spy), trace element and biomarker ratios from the Hongmiaozi Basin (North China) and unravel the response of continental lakes under the influence of early Aptian extreme climate conditions. According to the stratigraphic chronology (122-118 Ma) and carbon isotope correlations, terrestrial sediment was influenced by the early Aptian Oceanic Anoxic Event (OAE1a). The results show that the Xiahuapidianzi Group experienced a significant warming process under negative excursions in carbon isotopes due to the influence of increased carbon dioxide partial pressure (pCO2). The climate varied from warm and humid to hot and arid (high Sr/Cu, low Rb/Sr, calcareous mudstone), the evaporation and salinity increased (high Sr/Ba and B/Ga), and land input sources decreased (low Zr, Ti and Th). Moreover, high total organic carbon (TOC) content was source from bacteria, algae (n-alkanes), and euxinic depositional environments (Pr/Ph, Cu/Zn and U V Mo). In the stage of continuous carbon isotopes positive excursion, organic matter accumulated rapidly. A paleolake environment model has provided a better understanding of current global climate issues under global warming caused by increased carbon dioxide concentrations.

Palaeoenvironmental evolution of formation of Bayanjargalan oil shale: evidence from trace elements and biomarkers.

The genetic type of the Bayanerhet Formation oil shale in the Bayanjargalan mine area is an inland lacustrine oil shale deposit. Inorganic element analysis and organic geochemical testing of oil shale samples collected in three boreholes show that the Bayanerhet Formation oil shale has relatively high organic contents, e.g., average TOC values of 6.53, 7.32 and 8.84 (corresponding to oil contents of 5.49%, 6.07% and 7.50%) in boreholes BJ3807, BJ3405 and BJ3005, respectively. Analysis of organic matter sources with biomarkers indicates that lower aquatic organisms such as algae contribute more to the organic matter than higher plants do. According to research on the values of Fe2O3/FeO, Rb/Sr and w (La) n/w (Yb)n in cores from the three boreholes, the Bayanjargalan oil shale is inferred to have formed in a humid paleoclimate with a relatively high sedimentation rate. In research on the evolution of the paleoaquifer in which the oil shale formed, the values of Fe3+/Fe2+, V/V + Ni, Ni/V, Ceanom and δCe are applied as sensitive indicators of the redox conditions in the aqueous medium. These values indicate that the Bayanjargalan oil shale formed in a water body with a weak redox environment. Moreover, the values of Ca/(Ca + Fe) and Sr/Ba and the values of gammacerane/αßC30 hopane in biomarkers show that the oil shale was formed in a saltwater environment. Analysis of Mo and U shows high endogenous lake productivity, corresponding to high TOC, which suggests that the lacustrine productivity played an important role in organic matter enrichment. The Lower Cretaceous Bayanerhet Formation (K1bt) in the Bayanjargalan mine area encompasses a complete sequence and was formed during lowstand, transgression, highstand and regression periods. The dominant oil shale deposits were formed in the transgression system tract and high stand system tract, and these oil shales have a high oil content and stable occurrence. A large set of thick, high-TOC and high-oil-content oil shales in the second member of the Bayanerhet Formation was deposited under such conditions. The abundant terrigenous supply under warm and humid conditions significantly promoted the primitive biological productivity, and the weak redox saltwater environment had relatively high productivity. All the favorable conditions promoted the formation of high-quality oil shale.

Sedimentology, petrography, and reservoir quality of the Zarga and Ghazal formations in the Keyi oilfield, Muglad Basin, Sudan.

The Zarga and Ghazal formations constitute important reservoirs across the Muglad Basin, Sudan. Nevertheless, the sedimentology and diagenesis of these reservoir intervals have hitherto received insignificant research attention. Detailed understanding of sedimentary facies and diagenesis could enhance geological and geophysical data for better exploration and production and minimize risks. In this study, subsurface reservoir cores representing the Zarga formation (1114.70-1118.50 m and 1118.50-1125.30 m), and the Ghazal formation (91,403.30-1406.83 m) were subjected to sedimentological (lithofacies and grain size), petrographic/mineralogic (thin section, XRD, SEM), and petrophysical (porosity and permeability) analyses to describe their reservoir quality, provenance, and depositional environments. Eight (8) different lithofacies, texturally characterized as moderately to well-sorted, and medium to coarse-grained, sub-feldspathic to feldspathic arenite were distinguished in the cored intervals. Mono-crystalline quartz (19.3-26.2%) predominated over polycrystalline quartz (2.6-13.8%), feldspar (6.6-10.3%), and mica (1.4-7.6%) being the most prominent constituent of the reservoir rocks. Provenance plot indicated the sediments were from a transitional continental provenance setting. The overall vertical sequence, composition, and internal sedimentary structures of the lithofacies suggest a fluvial-to-deltaic depositional environment for the Ghazal formation, while the Zarga formation indicated a dominant deltaic setting. Kaolinite occurs mainly as authigenic mineral, while carbonates quantitatively fluctuate with an insignificant amount of quartz overgrowths in most of the analyzed cores. Integration of XRD, SEM, and thin section analysis highlights that kaolinite, chlorite, illite, and smectite are present as authigenic minerals. Pore-destroying diagenetic processes (e.g. precipitation, cementation, and compaction etc.) generally prevailed over pore-enhancing processes (e.g. dissolution). Point-counted datasets indicate a better reservoir quality for the Ghazal formation (ɸ = 27.7% to 30.7%; K = 9.65 mD to 1196.71 mD) than the Zarga formation (17.9% to 24.5%; K = 1051.09 mD to 1090.45 mD).

[Research on Oil Sands Spectral Characteristics and Oil Content by Remote Sensing Estimation].

Visible and near infrared spectroscopy is a proven technology to be widely used in identification and exploration of hydrocarbon energy sources with high spectral resolution for detail diagnostic absorption characteristics of hydrocarbon groups. The most prominent regions for hydrocarbon absorption bands are 1,740-1,780, 2,300-2,340 and 2,340-2,360 nm by the reflectance of oil sands samples. These spectral ranges are dominated by various C-H overlapping overtones and combination bands. Meanwhile, there is relatively weak even or no absorption characteristics in the region from 1,700 to 1,730 nm in the spectra of oil sands samples with low bitumen content. With the increase in oil content, in the spectral range of 1,700-1,730 nm the obvious hydrocarbon absorption begins to appear. The bitumen content is the critical parameter for oil sands reserves estimation. The absorption depth was used to depict the response intensity of the absorption bands controlled by first-order overtones and combinations of the various C-H stretching and bending fundamentals. According to the Pearson and partial correlation relationships of oil content and absorption depth dominated by hydrocarbon groups in 1,740-1,780, 2,300-2,340 and 2,340-2,360 nm wavelength range, the scheme of association mode was established between the intensity of spectral response and bitumen content, and then unary linear regression(ULR) and partial least squares regression (PLSR) methods were employed to model the equation between absorption depth attributed to various C-H bond and bitumen content. There were two calibration equations in which ULR method was employed to model the relationship between absorption depth near 2,350 nm region and bitumen content and PLSR method was developed to model the relationship between absorption depth of 1,758, 2,310, 2,350 nm regions and oil content. It turned out that the calibration models had good predictive ability and high robustness and they could provide the scientific basis for rapid estimation of oil content in oil sands in future.