OIL MIGRATION HISTORY OF THE OFFSHORE CANNING BASIN

2000 ◽  
Vol 40 (2) ◽  
pp. 133 ◽  
Author(s):  
M. Lisk ◽  
J. Ostby ◽  
N.J. Russell ◽  
G.W. O’Brien
Keyword(s):  
Fluid Inclusion ◽  
Acid Leaching ◽  
Reservoir Quality ◽  
Oil Migration ◽  
North West ◽  
Canning Basin ◽  
Carbonate Cement ◽  
Migration History ◽  
Potential Reservoir ◽  
Porosity And Permeability

The dual issues of the presence or absence of a viable, oil-prone petroleum system and reservoir quality represent key exploration uncertainties in the lightly explored Offshore Canning Basin, North West Shelf. To better quantify these factors, a detailed fluid inclusion investigation of potential reservoir horizons within the basin has been undertaken. The results have been integrated with regional petroleum geology and Synthetic Aperture Radar (SAR) oil seep data to better understand the oil migration risk in the region.The fluid inclusion data provide confirmation of widespread oil migration at multiple Mesozoic and Palaeozoic levels, including those wells that are remote from the likely source kitchens. The lack of evidence for present or palaeo-oil accumulations is consistent with the proposition that none of the currently water-wet wells appear to have tested a valid structure. These observations, when combined with the presence of numerous direct hydrocarbon indicators on seismic data and a number of oil slicks (from SAR data) at the basin’s edge, suggest that the potential for oil charge to valid structures is much higher than previously recognised.Petrographic analysis of the tight, gas-bearing, Triassic sandstones in Phoenix–1 suggests that the low porosity and permeability is the result of late poikilotopic carbonate cement. Significantly, the presence of oil inclusions within quartz overgrowths that pre-date the carbonate indicates that oil migration began prior to crystallisation of carbonate. Fluid inclusion palaeotemperatures combined with a 1D basin model suggest that trapping of oil as inclusions occurred in the Early to Middle Cretaceous and that predictions of reservoir quality using available water-wet wells could seriously under-estimate porositypermeability levels in potential traps that were charged with oil at about 100 Ma. Indeed, acid leaching of core plugs from Phoenix–1 indicates that removal of diagenetic carbonate results in significant permeability increase with obvious implications for the producibility of any future oil discovery. Further, evidence of Early Cretaceous oil charge has implications for the size and locality of source kitchens compared to that observed at the current day.Collectively, the data indicate the area has received widespread oil migration and suggest future exploration, even to relatively deep levels, may be successful if valid traps can be delineated.

A PROCESS FOR PREDICTING POROSITY AND PERMEABILITY IN DEEP EARLY JURASSIC/TRIASSIC TARGETS, AUSTRALIAN NORTH WEST SHELF

1998 ◽  
Vol 38 (1) ◽  
pp. 759
Author(s):  
P.C. Smalley ◽  
D. Jablonski ◽  
I. Simpson
Keyword(s):  
Early Jurassic ◽  
Reservoir Quality ◽  
Burial Depth ◽  
Core Analysis ◽  
North West ◽  
Geological Processes ◽  
Porosity And Permeability ◽  
Size Sorting ◽  
Model Reliability ◽  
Deep Exploration

In deep exploration prospects, reservoir quality is often a key risk. We describe a hybrid empirical-theoretical approach to minimise this risk:Use available regional petrographic-sedimentological data to tune theoretical depth-porosity-permeability curves.Verify that the model correctly represents the controlling geological processes by comparing these curves to core analysis data.Re-tune the model to the expected conditions in the deep prospects, using empirical quartz cementation predictions, regional depositional models and pressure prognoses from basin modelling.Use the re-tuned model to extrapolate porosity to the new depth, then predicting permeability from porosity.Eight studied wells in the Early Jurassic/Triassic, Dampier Sub-basin, provided an understanding of regional diagenetic style and the major reservoir quality controls. BP's PermPredictor model was used to construct regional, zone-specific depth-porosity-permeability curves from the petrographic and sedimentological data: sand ductile grain content, grain size, sorting and quartz cementation. Quartz cement correlates with burial depth, beginning at ~2,200 m and increasing by seven per cent (± two per cent) per km.The regional modelled depth-porosity-permeability relations agree well with the core analysis dataset, indicating model reliability. The modelled curves were then re-tuned to the predicted conditions in two notional exploration prospects, with top-structure depths of 4.7 km (Prospect 1) and 4.4 km (Prospect 2), the latter of these being overpressured. Predicted porosities were 5−11 per cent in Prospect 1 and ll−17per cent in Prospect 2, with permeabilities of 30−250 mD and 400−1,000 mD respectively assuming a clean sand composition. A dirty sand model (less likely) predicts

scholarly journals Precious Metal Enrichment at the Myra Falls VMS Deposit, British Columbia, Canada

Geosciences ◽  
2018 ◽  
Vol 8 (11) ◽  
pp. 422
Author(s):  
Daniel Marshall ◽  
Carol-Anne Nicol ◽  
Robert Greene ◽  
Rick Sawyer ◽  
Armond Stansell ◽  
...  
Keyword(s):  
Fluid Inclusion ◽  
Precious Metal ◽  
Metal Enrichment ◽  
Sea Floor ◽  
North West ◽  
Low Salinity ◽  
Volcanogenic Massive Sulphide ◽  
Igneous Fluids ◽  
Homogenization Temperatures ◽  
Water Depths

Gold, present as electrum, in the Battle Gap, Ridge North-West, HW, and Price deposits at the Myra Falls mine, occurs in late veinlets cutting the earlier volcanogenic massive sulphide (VMS) lithologies. The ore mineral assemblage containing the electrum comprises dominantly galena, tennantite, bornite, sphalerite, chalcopyrite, pyrite, and rarely stromeyerite, and is defined as an Au-Zn-Pb-As-Sb association. The gangue is comprised of barite, quartz, and minor feldspathic volcanogenic sedimentary rocks and clay, comprised predominantly of kaolinite with subordinate illite. The deposition of gold as electrum in the baritic upper portions of the sulphide lenses occurs at relatively shallow water depths beneath the sea floor. Primary, pseudosecondary, and secondary fluid inclusions, petrographically related to gold, show boiling fluid inclusion assemblages in the range of 123 to 173 °C, with compositions and eutectic melt temperatures consistent with seawater at approximately 3.2 wt % NaCl equivalent. The fluid inclusion homogenization temperatures are consistent with boiling seawater corresponding to water depths ranging from 15 to 125 m. Slightly more dilute brines corresponding to salinities of approximately 1 wt % NaCl indicate that there is input from very low-salinity brines, which could represent a transition from subaqueous VMS to epithermal-like conditions for precious metal enrichment, mixing with re-condensed vapor, or very low-salinity igneous fluids.

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 LA-ICP-MS U-Pb dating and geochemical characterization of oil inclusion-bearing calcite cements: Constraints on primary oil migration in lacustrine mudstone source rocks

2021 ◽  
Author(s):  
Ao Su ◽  
Honghan Chen ◽  
Yue-xing Feng ◽  
Jian-xin Zhao
Keyword(s):  
Fluid Inclusion ◽  
Inductively Coupled Plasma ◽  
Homogenization Temperature ◽  
Source Rocks ◽  
Oil Migration ◽  
Carbon And Oxygen Isotope ◽  
Fluorescence Characteristics ◽  
Calcite Veins ◽  
Migration Event

To date, few isotope age constraints on primary oil migration have been reported. Here we present U-Pb dating and characterization of two fracture-filling, oil inclusion-bearing calcite veins hosted in the Paleocene siliciclastic mudstone source rocks in Subei Basin, China. Deposition age of the mudstone formation was estimated to be ca. 60.2−58.0 Ma. The first vein consists of two major phases: a microcrystalline-granular (MG) calcite phase, and a blocky calcite phase, each showing distinctive petrographic features, rare earth element patterns, and carbon and oxygen isotope compositions. The early MG phase resulted from local mobilization of host carbonates, likely associated with disequilibrium compaction over-pressuring or tectonic extension, whereas the late-filling blocky calcite phase was derived from overpressured oil-bearing fluids with enhanced fluid-rock interactions. Vein texture and fluorescence characteristics reveal at least two oil expulsion events, the former represented by multiple bitumen veinlets postdating the MG calcite generation, and the latter marked by blue-fluorescing primary oil inclusions synchronous with the blocky calcite cementation. The MG calcite yields a laser ablation−inductively coupled plasma−mass spectrometry U-Pb age of 55.6 ± 1.4 Ma, constraining the earliest timing of the early oil migration event. The blocky calcite gives a younger U-Pb age of 47.8 ± 2.3 Ma, analytically indistinguishable from the U-Pb age of 46.5 ± 1.7 Ma yielded by the second calcite vein. These two ages define the time of the late oil migration event, agreeing well with the age estimate of 49.7−45.2 Ma inferred from fluid-inclusion homogenization temperature and published burial models. Thermodynamic modeling shows that the oil inclusions were trapped at ∼27.0−40.9 MPa, exceeding corresponding hydrostatic pressures (23.1−26.7 MPa), confirming mild-moderate overpressure created by oil generation-expulsion. This integrated study combining carbonate U-Pb dating and fluid-inclusion characterization provides a new approach for reconstructing pressure-temperature-composition-time points in petroleum systems.

Reservoir Quality of the Miocene Formation Gas Deposits, Onshore Abu Dhabi

2021 ◽  
Author(s):  
Catherine Breislin ◽  
Laura Galluccio ◽  
Kate Al Tameemi ◽  
Riaz Khan ◽  
Atef Abdelaal
Keyword(s):  
Depositional Environment ◽  
Middle Miocene ◽  
Quality Analysis ◽  
Reservoir Quality ◽  
Carbonate Facies ◽  
Pore System ◽  
Thin Sections ◽  
Reservoir Architecture ◽  
Porosity And Permeability ◽  
Permeability Anisotropy

Abstract Understanding reservoir architecture is key to comprehend the distribution of reservoir quality when evaluating a field's prospectivity. Renewed interest in the tight, gas-rich Middle Miocene anhydrite intervals (Anh-1, Anh-2, Anh-3, Anh-4 and Anh-6) by ADNOC has given new impetus to improving its reservoir characterisation. In this context, this study provides valuable new insights in geological knowledge at the field scale within a formation with limited existing studies. From a sedimentological point of view, the anhydrite layers of the Miocene Formation, Anh-1, Anh-2, Anh-3, Anh-4 and Anh-6 (which comprise three stacked sequences: Bur1, Bur2 and Bur3; Hardenbol et al., 1998), have comparable depositional organisation throughout the study area. Bur1 and Bur2 are characterised by an upward transition from intertidal-dominated deposits to low-energy inner ramp-dominated sedimentation displaying reasonably consistent thickness across the area. Bur3 deposits imply an initial upward deepening from an argillaceous intertidal-dominated to an argillaceous subtidal-dominated setting, followed by an upward shallowing into intertidal and supratidal sabkha-dominated environments. This Bur3 cycle thickens towards the south-east due to a possible deepening, resulting in the subtle increase in thickness of the subtidal and intertidal deposits occurring around the maximum-flooding surface. The interbedded relationship between the thin limestone and anhydrite layers within the intertidal and proximal inner ramp deposits impart strong permeability anisotropy, with the anhydrite acting as significant baffles to vertical fluid flow. A qualitative reservoir quality analysis, combining core sedimentology data from 10 wells, 331 CCA data points, 58 thin-sections and 10 SEM samples has identified that reservoir layers Anh-4 and Anh-6 contain the best porosity and permeability values, with the carbonate facies of the argillaceous-prone intertidal and distal inner ramp deposits hosting the best reservoir potential. Within these facies, the pore systems within the carbonate facies are impacted by varying degrees of dolomitisation and dissolution which enhance the pore system, and cementation (anhydrite and calcite), which degrade the pore system. The combination of these diagenetic phases results in the wide spread of porosity and permeability data observed. The integration of both the sedimentological features and diagenetic overprint of the Middle Miocene anhydrite intervals shows the fundamental role played by the depositional environment in its reservoir architecture. This study has revealed the carbonate-dominated depositional environment groups within the anhydrite stratigraphic layers likely host both the best storage capacity and flow potential. Within these carbonate-dominated layers, the thicker, homogenous carbonate deposits would be more conducive to vertical and lateral flow than thinner interbedded carbonates and anhydrites, which may present as baffles or barriers to vertical flow and create significant permeability anisotropy.

The Uniqueness of Heterogeneous Globigerina Limestone Reservoir and The Importance of Integrated Rock Type Definition for Field Development Plan: Case Study in Madura Strait, East Java

2021 ◽  
Author(s):  
E. P. Putra
Keyword(s):  
Water Saturation ◽  
Rock Type ◽  
Reservoir Rock ◽  
Reservoir Quality ◽  
Secondary Porosity ◽  
Field Development ◽  
Core Data ◽  
Type Definition ◽  
Volume Porosity ◽  
Porosity And Permeability

The Globigerina Limestone (GL) is the main reservoir of the seven gas fields that will be developed in the Madura Strait Block. The GL is a heterogeneous and unique clastic carbonate. However, the understanding of reservoir rock type of this reservoir are quite limited. Rock type definition in heterogeneous GL is very important aspect for reservoir modeling and will influences field development strategy. Rock type analysis in this study is using integration of core data, wireline logs and formation test data. Rock type determination applies porosity and permeability relationship approach from core data, which related to pore size distribution, lithofacies, and diagenesis. The analysis resulted eight rock types in the Globigerina Limestone reservoir. Result suggests that rock type definition is strongly influenced by lithofacies, which is dominated by packstone and wackestone - packstone. The diagenetic process in the deep burial environment causes decreasing of reservoir quality. Then the diagenesis process turns to be shallower in marine phreatic zone and causes dissolution which increasing the reservoir quality. Moreover, the analysis of rock type properties consist of clay volume, porosity, permeability, and water saturation. The good quality of a rock type will have the higher the porosity and permeability. The dominant rock type in this study area is RT4, which is identical to packstone lithofasies that has 0.40 v/v porosity and 5.2 mD as average permeability. The packstone litofacies could be found in RT 5, 6, 7, even 8 due to the increased of secondary porosity. It could also be found at a lower RT which is caused by intensive cementation.

Factors Controlling Porosity Permeability Relationship for Reservoir Quality Prediction: A Case Study of Malay Basin Reservoir, Malaysia

2021 ◽  
Author(s):  
Fadzlin Hasani Kasim ◽  
Budi Priyatna Kantaatmadja ◽  
Wan Nur Wan M Zainudin ◽  
Amita Ali ◽  
Hasnol Hady Ismail ◽  
...  
Keyword(s):  
Reservoir Characterization ◽  
Visual Analysis ◽  
Mineral Dissolution ◽  
Rock Properties ◽  
Reservoir Quality ◽  
Hydrocarbon Potential ◽  
Lower Grade ◽  
Reservoir Properties ◽  
Reservoir Evaluation ◽  
Porosity And Permeability

Abstract Predicting the spatial distribution of rock properties is the key to a successful reservoir evaluation for hydrocarbon potential. However, a reservoir with a complex environmental setting (e.g. shallow marine) becomes more challenging to be characterized due to variations of clay, grain size, compaction, cementation, and other diagenetic effects. The assumption of increasing permeability value with an increase of porosity may not be always the case in such an environment. This study aims to investigate factors controlling the porosity and permeability relationships at Lower J Reservoir of J20, J25, and J30, Malay Basin. Porosity permeability values from routine core analysis were plotted accordingly in four different sets which are: lithofacies based, stratigraphic members based, quartz volume-based, and grain-sized based, to investigate the trend in relating porosity and permeability distribution. Based on petrographical studies, the effect of grain sorting, mineral type, and diagenetic event on reservoir properties was investigated and characterized. The clay type and its morphology were analyzed using X-ray Diffractometer (XRD) and Spectral electron microscopy. Results from porosity and permeability cross-plot show that lithofacies type play a significant control on reservoir quality. It shows that most of the S1 and S2 located at top of the plot while lower grade lithofacies of S41, S42, and S43 distributed at the middle and lower zone of the plot. However, there are certain points of best and lower quality lithofacies not located in the theoretical area. The detailed analysis of petrographic studies shows that the diagenetic effect of cementation and clay coating destroys porosity while mineral dissolution improved porosity. A porosity permeability plot based on stratigraphic members showed that J20 points located at the top indicating less compaction effect to reservoir properties. J25 and J30 points were observed randomly distributed located at the middle and bottom zone suggesting that compaction has less effect on both J25 and J30 sands. Lithofacies description that was done by visual analysis through cores only may not correlate-able with rock properties. This is possibly due to the diagenetic effect which controls porosity and permeability cannot visually be seen at the core. By incorporating petrographical analysis results, the relationship between porosity, permeability, and lithofacies can be further improved for better reservoir characterization. The study might change the conventional concept that lower quality lithofacies does not have economic hydrocarbon potential and unlock more hydrocarbon-bearing reserves especially in these types of environmental settings.

scholarly journals Small-scale diagenetic facies heterogeneity controls porosity and permeability pattern in reservoir sandstones

2020 ◽  
Vol 79 (18) ◽  
Author(s):  
Matthias Heidsiek ◽  
Christoph Butscher ◽  
Philipp Blum ◽  
Cornelius Fischer
Keyword(s):  
Reservoir Rock ◽  
Rock Properties ◽  
Small Scale ◽  
Reservoir Quality ◽  
Permian Basin ◽  
Gas Reservoirs ◽  
Spatial Fluctuations ◽  
Porosity And Permeability ◽  
Reservoir Sandstones ◽  
Diagenetic Facies

Abstract The fluvial-aeolian Upper Rotliegend sandstones from the Bebertal outcrop (Flechtingen High, Germany) are the famous reservoir analog for the deeply buried Upper Rotliegend gas reservoirs of the Southern Permian Basin. While most diagenetic and reservoir quality investigations are conducted on a meter scale, there is an emerging consensus that significant reservoir heterogeneity is inherited from diagenetic complexity at smaller scales. In this study, we utilize information about diagenetic products and processes at the pore- and plug-scale and analyze their impact on the heterogeneity of porosity, permeability, and cement patterns. Eodiagenetic poikilitic calcite cements, illite/iron oxide grain coatings, and the amount of infiltrated clay are responsible for mm- to cm-scale reservoir heterogeneities in the Parchim formation of the Upper Rotliegend sandstones. Using the Petrel E&P software platform, spatial fluctuations and spatial variations of permeability, porosity, and calcite cements are modeled and compared, offering opportunities for predicting small-scale reservoir rock properties based on diagenetic constraints.

Fault-seal potential of the Palaeozoic in the northwest Canning Basin

2012 ◽  
Vol 52 (1) ◽  
pp. 427
Author(s):  
Julian Strand ◽  
Antoine Vaslin ◽  
Laurent Langhi
Keyword(s):  
Injection Site ◽  
Western Australia ◽  
Co2 Sequestration ◽  
Hydrocarbon Exploration ◽  
Early Permian ◽  
North West ◽  
Canning Basin ◽  
Price Point ◽  
Exploration Drilling ◽  
Gas Fields

As part of a Geological Survey of Western Australia organised review of the Canning Basin involving UWA and CSIRO, the fault-seal potential for the northwest Canning Basin has been analysed. This study has two foci: firstly identifying potential for fault-bound hydrocarbon reservoirs in the Early Permian (Poole Sandstone and Upper Grant Group). Secondly, James Price Point, 55 km north of Broome, is the chosen location for an LNG facility to service the northern North West Shelf gas fields. As such, the study aims to highlight potential CO2 sequestration reservoir sequences occurring inside 200 km of James Price Point, the economically feasible distance for CO2 delivery to an injection site. Historically, hydrocarbon exploration drilling in the Fitzroy Trough targeted anticlinal structures, which proved unsuccessful due to localised, but significant, erosion of the Permian sequence including the Noonkanbah Formation top-seal on anticlinal crests. Given there is potential for untested, fault-bound traps to exist, which might provide an alternative to the anticlinal traps, it will be useful to identify the distribution of shale-rich, top-seal and fault-seal prone sequences, and where these occur at suitable reservoir depths. The study shows the Early Permian sequences on the flanking terraces of the Fitzroy Trough commonly have suitable top-seal and fault-seal prone sediments. In wells analysed in the Fitzroy Trough itself, the Early Permian sequence is poorly represented, but Permo-Carboniferous sediments observed indicate some sealing potential might exist there. Moving south onto the Broome Platform and into the Wiluna Sub-basin, the Early Permian sequences still display some sealing potential, but Ordovician units might provide more suitable targets for sequestration in these areas.

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