SEDIMENTATION AND PETROLEUM POTENTIAL OF THE JURASSIC SEQUENCE IN THE SOUTHWESTERN GREAT ARTESIAN BASIN

1969 ◽  
Vol 9 (1) ◽  
pp. 97
Author(s):  
O. W. Nugent
Keyword(s):  
Reservoir Rock ◽  
Petroleum Reservoir ◽  
Petroleum Potential ◽  
Artesian Basin ◽  
Fine Grained ◽  
Great Artesian Basin ◽  
Facies Change ◽  
Area North ◽  
Sandstone Facies ◽  
Jurassic Sequence

Along the western margins of the southwestern Great Artesian basin the Jurassic sequence is an almost continuous sandstone section. In the eastern part of the same area, this sandstone sequence is broken by two shale-siltstone intervals, the Birkhead and Westbourne Formations. Towards the western margins of the basin these facies change into sandstone. The Murta Member of the Mooga Formation develops in the area north of Lake Frome through a facies change in the upper part of this formation from sandstone to siltstone and shale. It is postulated that the depositional conditions in the southwestern Great Artesian basin were dominantly fluviatile during most of the Jurassic and that the fine grained sediments of the Birkhead and Westbourne Formations and the Murta Member of the Mooga Formation were deposited under low energy lacustrine conditions. Abundant good quality potential petroleum reservoir rock exists throughout the entire Jurassic sequence. The lack of hydrocarbon filled traps found to date and the change of the main siltstone-shale intervals into sandstone facies in the west and southwest, imply that the Jurassic in the southwestern Great Artesian basin has been effectively flushed. However, the complex facies relationship of the sandstone and shale beds indicates that stratigraphically controlled traps may exist. The most prospective part of the Jurassic for commercial hydrocarbons appears to be in the lower part of the Hutton Sandstone.

Tandem scanning confocal light microscopy as compared with x-ray diffraction for characterizing the behavior of clays in fluid-saturated petroleum reservoir rock

1989 ◽  
Vol 47 ◽  
pp. 148-149
Author(s):  
C.J. Stuart ◽  
B.E. Viani ◽  
J. Walker ◽  
T.H. Levesque
Keyword(s):  
Light Microscopy ◽  
Image Plane ◽  
Reservoir Rock ◽  
Depth Of Field ◽  
Objective Lens ◽  
Scanning System ◽  
Light Sources ◽  
Petroleum Reservoir ◽  
Image Recording ◽  
Scan Speed

Many techniques of imaging used to characterize petroleum reservoir rocks are applied to dehydrated specimens. In order to directly study behavior of fines in reservoir rock at conditions similar to those found in-situ these materials need to be characterized in a fluid saturated state.Standard light microscopy can be used on wet specimens but depth of field and focus cannot be obtained; by using the Tandem Scanning Confocal Microscope (TSM) images can be produced from thin focused layers with high contrast and resolution. Optical sectioning and extended focus images are then produced with the microscope. The TSM uses reflected light, bulk specimens, and wet samples as opposed to thin section analysis used in standard light microscopy. The TSM also has additional advantages: the high scan speed, the ability to use a variety of light sources to produce real color images, and the simple, small size scanning system. The TSM has frame rates in excess of normal TV rates with many more lines of resolution. This is accomplished by incorporating a method of parallel image scanning and detection. The parallel scanning in the TSM is accomplished by means of multiple apertures in a disk which is positioned in the intermediate image plane of the objective lens. Thousands of apertures are distributed in an annulus, so that as the disk is spun, the specimen is illuminated simultaneously by a large number of scanning beams with uniform illumination. The high frame speeds greatly simplify the task of image recording since any of the normally used devices such as photographic cameras, normal or low light TV cameras, VCR or optical disks can be used without modification. Any frame store device compatible with a standard TV camera may be used to digitize TSM images.

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

2021 ◽  
Vol 11 (1) ◽  
Author(s):  
Yousif M. Makeen ◽  
Xuanlong Shan ◽  
Mutari Lawal ◽  
Habeeb A. Ayinla ◽  
Siyuan Su ◽  
...  
Keyword(s):  
Clay Content ◽  
Petroleum Exploration ◽  
Reservoir Quality ◽  
Burial Depth ◽  
Petroleum Reservoir ◽  
Fine Grained ◽  
Porosity And Permeability ◽  
Negative Role ◽  
Crevasse Splay ◽  
Channel Deposits

AbstractThe 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.

scholarly journals Enhancing geological and hydrogeological understanding of the Precipice Sandstone aquifer of the Surat Basin, Great Artesian Basin, Australia, through model inversion of managed aquifer recharge datasets

2019 ◽  
Vol 28 (1) ◽  
pp. 175-192
Author(s):  
Phil Hayes ◽  
Chris Nicol ◽  
Andrew D. La Croix ◽  
Julie Pearce ◽  
Sebastian Gonzalez ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Groundwater Resources ◽  
Regional Scale ◽  
Managed Aquifer Recharge ◽  
Gas Production ◽  
Aquifer Recharge ◽  
Model Inversion ◽  
Artesian Basin ◽  
Geological Interpretation ◽  
Great Artesian Basin

AbstractThe Precipice Sandstone is a major Great Artesian Basin aquifer in the Surat Basin, Queensland, Australia, which is used for water supply and production of oil and gas. This report describes use of observed groundwater pressure responses to managed aquifer recharge (MAR) at a regional scale to test recent geological descriptions of Precipice Sandstone extent, and to inform its hydrogeological conceptualisation. Since 2015, two MAR schemes have injected over 20 GL of treated water from coal seam gas production into the Precipice Sandstone, with pressure responses rapidly propagating over 100 km, indicating high aquifer diffusivity. Groundwater modelling of injection and inversion of pressure signals using PEST software shows the spatial variability of aquifer properties, and indicates that basin in-situ stresses and faulting exert control on permeability. Extremely high permeability, up to 200 m/day, occurs in heavily fractured regions with a dual-porosity flow regime. The broader-scale estimates of permeability approach an order of magnitude higher than previous studies, which has implications for the management of water resources in the Precipice Sandstone. Results also show the Precipice Sandstone to have broadly isotropic permeability. The results also support a recent geological interpretation of the Precipice Sandstone as having more limited lateral extent than initially considered. The study shows the effective use of MAR injection data to improve geological and hydrogeological understanding through groundwater model inversion. It also demonstrates the utility of combining hydrogeological and reservoir-engineer datasets in areas explored and developed for both groundwater resources and oil and gas resources.

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