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 Spatial variation in porosity and permeability of the Rupel Clay Member in the Netherlands

2016 ◽  
Vol 95 (3) ◽  
pp. 253-268 ◽  
Author(s):  
Hanneke Verweij ◽  
Geert-Jan Vis ◽  
Elke Imberechts
Keyword(s):  
The Netherlands ◽  
Spatial Variation ◽  
Clay Content ◽  
Burial Depth ◽  
Southeastern Part ◽  
Boom Clay ◽  
The North ◽  
Sealing Capacity ◽  
Porosity And Permeability ◽  
Permeability Data

AbstractThe spatial distribution of porosity and permeability of the Rupel Clay Member is of key importance to evaluate the spatial variation of its sealing capacity and groundwater flow condition. There are only a limited number of measured porosity and permeability data of the Rupel Clay Member in the onshore Netherlands and these data are restricted to shallow depths in the order of tens of metres below surface. Grain sizes measured by laser diffraction and SediGraph® in samples of the Rupel Clay Member taken from boreholes spread across the country were used to generate new porosity and permeability data for the Rupel Clay Member located at greater burial depth. Effective stress and clay content are important parameters in the applied grain-size based calculations of porosity and permeability.The calculation method was first tested on measured data of the Belgian Boom Clay. The test results showed good agreement between calculated permeability and measured hydraulic conductivity for depths exceeding 200m.The spatial variation in lithology, heterogeneity and also burial depth of the Rupel Clay Member in the Netherlands are apparent in the variation of the calculated permeability. The samples from the north of the country consist almost entirely of muds and as a consequence show little lithology-related variation in permeability. The vertical variation in permeability in the more heterogeneous Rupel Clay Member in the southern and east-southeastern part of the country can reach several orders of magnitude due to increased permeability of the coarser-grained layers.

scholarly journals The effect of fluvial environments on sediment bleaching and Holocene luminescence ages — A case study from the German Alpine Foreland

2013 ◽  
Vol 40 (4) ◽  
pp. 283-293 ◽  
Author(s):  
Patrick Schielein ◽  
Johanna Lomax
Keyword(s):  
Statistical Modelling ◽  
Moderate Degree ◽  
Point Bar ◽  
Fine Grained ◽  
Sedimentary Environments ◽  
Fine Grain ◽  
Floodplain Deposits ◽  
Crevasse Splay ◽  
Channel Deposits ◽  
Floodplain Sediments

Abstract This study investigates the potential of luminescence to date deposits from different fluvial sedimentary environments; namely point bar deposits, sandy and silty channel fills and floodplain sediments. Samples were taken from Holocene (<5 ka) terraces of the Lech and Danube rivers, for which independent age constraint is available through 14C ages, archaeological data and historical maps. OSL-ages were obtained using small aliquots of coarse grain quartz for the majority of samples. Two further samples were dated by the IRSL-signals of polymineral fine grain extracts, as no sufficient number of coarse grains could be extracted from these sediments. In order to detect and ac-count for incomplete bleaching, we used the decision process suggested by Bailey and Arnold [Statistical modelling of single grain quartz De distributions and an assessment of procedures for estimating burial dose. Quaternary Science Reviews 25, 2475–2502, 2006]. Although their model was designed for single grains of quartz, our study shows that it is also applicable to multiple grains of quartz, pro-vided that a low number of luminescent grains is present on one aliquot. Luminescence ages of point bar deposits and a sandy channel fill correspond most closely to the independent age control. In the floodplain, sand-striped floodplain channel deposits were incompletely bleached to a moderate degree, yielding ages with acceptable overestimations, while fine-grained floodplain deposits were worst bleached. One crevasse splay deposit was so severely incompletely bleached that none of the age models was able to yield accurate ages.

PETROLEUM PROSPECTS, BLIGH WATER, FIJI

1972 ◽  
Vol 12 (1) ◽  
pp. 62
Author(s):  
A.W. Lindner
Keyword(s):  
Shallow Water ◽  
Sedimentary Rocks ◽  
Petroleum Exploration ◽  
Seismic Profiles ◽  
Fine Grained ◽  
Porosity And Permeability ◽  
Oil Seepage ◽  
The Government ◽  
Basement High ◽  
Offshore Petroleum

The Fiji Archipelago constitutes a segment of the island arc system of the southwest Pacific. The islands in the group comprise a mixture of igneous and sedimentary rocks including carbonates. The hydrocarbon potential of the region has been emphasised since the Tonga oil seepage drew the attention of the oil industry to this part of the globe in 1968.Southern Pacific Petroleum (Fiji) Limited was granted the first offshore petroleum concession in Fiji by the Government in 1969 and the negotiation for the concession resulted in the formulation of Fijian offshore petroleum exploration legislation. Reconnaissance sparker seismic shooting indicated the existence of stratified rocks beneath Bligh Water and subsequent aeromagnetics and multiple coverage seismic has confirmed the presence of a sedimentary basin.The oldest dated sedimentary rocks in Fiji are Eocene. They form part of a very thick sequence, including volcanics, ranging into Lower Miocene which regionally has been mildly metamorphosed. Locally this sequence has been intruded by intermediate to basic plutonic stocks which subsequently have been unroofed by widespread intra-Miocene erosion. This sequence constitutes the economic basement in the region. Middle to Upper Miocene and Pliocene clastic, marine, fossiliferous sediments and shallow water carbonates on the two main islands of Fiji were deposited in localised basins, generally in complex association with volcanic rocks.The sedimentary column contains considerable fine grained, dark coloured, marine elastics. Bioclastic limestone, also present in the sequence, has excellent porosity and permeability. Good reservoir character is similarly indicated for some of the coarser elastics, despite the lack of quartz.The seismic data, when integrated with the geology of the islands, infer that the deepest continuous reflection horizon represents the intra-Miocene unconformity; additionally, the data show that the Bligh Water Basin is divided into northern and southern components, divided by a basement high. The southern region appears more attractive for exploration as 7000 ft. (2100 m.) of section is indicated and the area is covered by shallow water. Faulting and drape features are the obvious structural forms present. Several discontinuous reflection events, commonly occurring at equivalent positions on different seismic profiles, may indicate presence of carbonate banks or cays similar to the type of carbonate deposits exposed in the succession onshore.

Controls on the reservoir quality of Late Cretaceous Springar Formation deep-water fan systems in the Vøring Basin

2017 ◽  
Vol 8 (1) ◽  
pp. 247-257 ◽  
Author(s):  
Alana Finlayson ◽  
Angela Melvin ◽  
Alex Guise ◽  
James Churchill
Keyword(s):  
Grain Size ◽  
Late Cretaceous ◽  
Clay Content ◽  
Coarse Grained ◽  
Reservoir Quality ◽  
Low Permeability ◽  
Quality Model ◽  
Depositional Facies ◽  
Porosity And Permeability ◽  
Vøring Basin

AbstractA new reservoir quality model is proposed for the Late Cretaceous Springar Formation sandstones of the Vøring Basin. Instead of a depth-related compactional control on reservoir quality, distinct high- and low-permeability trends are observed. Fan sequences which sit on the high-permeability trend are characterized by coarse-grained facies with a low matrix clay content. These facies represent the highest energy sandy turbidite facies within the depositional system, and were deposited in channelized or proximal lobe settings. Fan sequences on the low-permeability trend are characterized by their finer grain size and the presence of detrital clay, which has been diagenetically altered to a highly microporous, illitic, pore-filling clay. These fan sequences are interpreted to have been deposited in proximal–distal lobe environments. Original depositional facies determines the sorting, grain size and detrital clay content, and is the fundamental control on reservoir quality, as the illitization of detrital clay is the main mechanism for reductions in permeability. Core-scale depositional facies were linked to seismic-scale fan elements in order to better predict porosity and permeability within each fan system, allowing calibrated risking and ranking of prospects within the Springar Formation play.

scholarly journals Overview of potential geothermal reservoirs in Denmark

2020 ◽  
Vol 99 ◽  
Author(s):  
Rikke Weibel ◽  
Mette Olivarius ◽  
Henrik Vosgerau ◽  
Anders Mathiesen ◽  
Lars Kristensen ◽  
...  
Keyword(s):  
Mineralogical Composition ◽  
Green Energy ◽  
Alluvial Fan ◽  
Reservoir Quality ◽  
Burial Depth ◽  
High Porosity ◽  
Geothermal Resources ◽  
Geothermal Reservoirs ◽  
Entry Points ◽  
Porosity And Permeability

Abstract The Danish onshore subsurface contains very large geothermal resources that have the potential to make a significant contribution to transforming Danish energy consumption toward a more sustainable energy mix. Presently, only a minor fraction of this green energy is exploited in three small plants. The main factors that have hampered and delayed larger-scale deployment are related to uncertainties in the geological models, which inevitably lead to high economic risks that are difficult for smaller district heating companies to mitigate without support from a compensation scheme. To facilitate and stimulate much wider use of the Danish geothermal resources, the Geological Survey of Denmark and Greenland (GEUS) and other research institutes have conducted several regional research projects focusing on the geological and geochemical obstacles with the principal objective of reducing the exploration risks by selecting the best geological reservoirs. One of the most important geological factors causing uncertainty is the quality of the reservoirs and their ability to produce the expected volume of warm geothermal brine. Thus, great emphasis has been placed on investigating and understanding the relationships between reservoir sandstone, porosity, permeability, petrography, diagenetic processes and alterations related to variable sediment sources, basin entry points, depositional systems and climate, burial and thermal history. Mesozoic sandstones comprise the most important geothermal reservoirs in Denmark. Details concerning the reservoir quality are compiled and compared for the Lower Triassic Bunter Sandstone, Triassic Skagerrak, Upper Triassic – Lower Jurassic Gassum and Middle Jurassic Haldager Sand formations. The Bunter Sandstone Formation contains extensive aeolian and more confined fluvial sandstones with high porosity and permeability. However, highly saline formation water could be unfavourable. The Skagerrak Formation comprises well-sorted braided stream sandstones in the centre of the basin, and is otherwise characterised by muddy sandstones and alluvial fan conglomerates. An immature mineralogical composition has caused intensive diagenetic changes in the deepest buried parts of the basin. The Gassum Formation consists of shoreface, fluvial and estuarine sandstones interbedded with marine and lacustrine mudstones. In the upper part of the formation, the sandstone beds pinch out into mudstones towards the basin centre. Pervasive siderite- and calcite cement occurs locally in shallowly buried sandstones, and with burial depth the maximum abundances of quartz and ankerite cement increase. Sandstones of shallow burial represent excellent reservoirs. The relatively coarse grain size of the Haldager Sand Formation results in high porosity and permeability even at deep burial, so the formation comprises a high-quality geothermal reservoir. Substantial progress has been made, and a well-established regional geological model combined with reservoir quality is now available for areas with cored wells. This has enabled an improved estimation of reservoir quality between wells for exploration of geothermal reservoirs.

scholarly journals Controls of Depositional Environments on Reservoir Quality in Terms of Porosity and Permeability Gabo Field Niger Delta

2019 ◽  
Author(s):  
Richmond Ideozu ◽  
Tochukwu Nduaguibe
Keyword(s):  
Niger Delta ◽  
High Energy ◽  
Depositional Environments ◽  
Grain Size Analysis ◽  
Reservoir Quality ◽  
Fine Grained ◽  
Sedimentary Structures ◽  
Facies Associations ◽  
Porosity And Permeability ◽  
Distributary Channel

The controls of depositional environments on reservoir quality have been evaluated in terms of porosity and permeability of the Gabo Field, Niger Delta, Nigeria. Data used in this research include Well logs, Core data and photos, and grain size analysis for Wells 51 and 52 in the study area. Standard methods as applicable in petrophysical and sedimentological analysis has been adopted. Thirteen reservoir units have been identified in wells 51 and 52 which had 5 reservoirs cored each. The lithofacies units of the identified reservoirs across the study area, comprise pebbly sands, coarse -, medium -, fine- and very fine-grained sands, sandy mud, silty sands and heteroliths. The heteroliths &ndash; very fine-grained silty muds are highly bioturbated. Ophiomorpha and skolithos are the major trace fossils with sedimentary structures (ripple lamination, wavy lenticular and planar beds, cross bedded sands, coarsening and fining upward). The facies associations interpreted for the study area are Channel and Coastal barrier systems and the environment of deposition as distributary channel, upper and lower shoreface. The sedimentary processes that deposited facies ranged from high energy regimes, reworking by waves to low energy with periodic influx of silts and muds. The average porosity and permeability for reservoirs in Well 51 is 16.7% and 1317 Md, reservoirs in Well 52 is 28.2% and 2330Md whereas porosity range for the study area is 2% - 32% and permeability is 1.2 &ndash; 10600 Md. The reservoir quality reservoir of the sand units in Well 51 (7, 9 and 13) and Well 52 (5, 7, 9, 11 and 13) is excellent - good, this is because of the dynamics environments of deposition (upper shoreface and distributary channel) as well as the mechanisms that play out during deposition such as bioturbation, sorting, sedimentary structures formed. Whereas the poor quality across the reservoirs especially the lower shoreface and prodelta facies is as result of lack bioturbation, connectivity, multiplicity of burrows that may have been plugged by clay and intercalation of shale and sand (heteroliths). This research has shown that environments of deposition have direct influence the reservoir quality in terms of porosity and permeability.

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

DEFOSITIONAL FRAMEWORK AND DIAGENESIS OF THE LATE PERMIAN GAS RESERVOIRS OF THE BONAPARTE BASIN

1984 ◽  
Vol 24 (1) ◽  
pp. 299 ◽  
Author(s):  
M. R. Bhatia ◽  
M. Thomas ◽  
J. M. Boirie
Keyword(s):  
Clay Content ◽  
Coarse Grained ◽  
Reservoir Quality ◽  
Late Permian ◽  
Gas Reservoirs ◽  
Delta Front ◽  
Delta Plain ◽  
Porosity And Permeability ◽  
Calcite Cementation

Late Permian sandstones form the reservoir of the Tern and Petrel gas fields in the offshore Bonaparte Basin. The producing reservoirs of the Petrel field were deposited in various environments associated with a major northwesterly trending deltaic system. The producing sands in the Tern field were deposited in the shoreface environment of a barrier-bar system.The reservoir quality of the sands is controlled by the diagenesis, which is facies dependent. In the Petrel field, sandstones deposited in the upper delta plain and along the shoreline are clean, medium-to coarse-grained and highly quartzose but have very low porosity and permeability due to extensive quartz diagenesis. However, sands deposited in delta front and lower delta plain environments are medium to fine grained, argillaceous and have fair to good reservoir potential. In these sands, the dispersed clays formed coats and rims on quartz grains during early diagenesis and inhibited quartz overgrowth. In the Tern field, sands of the upper shoreface have poor reservoir quality due to early calcite cementation. However, finer-grained sandstones of the lower shoreface facies have good reservoir quality. The porosity in these sands is mainly primary and preserved due to low carbonate and high clay content. The processes of quartz and calcite cementation which drastically reduced the reservoir quality of the coarse-grained sands occurred early and were influenced by the texture of the sands and probably also by the chemical character of the formation waters.

NEW EXPLORATION TECHNIQUES IN THE ANALYSIS OF DIAGENETICALLY COMPLEX RESERVOIR SANDSTONES, SYDNEY BASIN, NSW

1989 ◽  
Vol 29 (1) ◽  
pp. 235
Author(s):  
D.S. Hamilton W.E. Galloway
Keyword(s):  
Oil And Gas ◽  
Gas Production ◽  
Petroleum Exploration ◽  
Quality Data ◽  
Careful Examination ◽  
Reservoir Quality ◽  
Primary Concern ◽  
Porosity And Permeability ◽  
Reservoir Sandstones ◽  
Drill Cores

The Sydney Basin, despite numerous encouraging shows of both free oil and gas from coal and petroleum exploration drilling, remains unproductive of commercial hydrocarbons. Reservoir potential has historically been the primary concern, owing to widespread distribution throughout the sequence of lithic, diagenetically- altered, clay- rich sandstones. This study aimed at defining areas of acceptable reservoir quality by careful examination of stratigraphic, depositional and diagenetic controls.Interpretation and extrapolation of reservoir distribution, attributes and quality were carried out within a genetic stratigraphic framework. Stratigraphic packages of widespread correlatability that were deposited during discrete episodes of basin filling provide the basis for delineation of component depositional systems and for further mapping of framework sandstone facies and associated mud rocks.The availability of numerous, continuous drill cores from existing coal bores and limited petroleum exploration wells provided an opportunity to directly quantify porosity and permeability. A visual method of estimating permeability was applied by comparison of the drill cores with a standard set of cores of known permeability. The comparison was made on fresh, dry rock surfaces with the aid of a binocular microscope at 20 × magnification. Reliability of the visual estimates was then assessed by laboratory measurement of a large representative sample set.Lithofacies maps of genetic stratigraphic packages define sand- body trends and allow interpretative extrapolation of reservoir facies tracts which, when integrated with the visually- estimated and laboratory- derived reservoir quality data, enabled mapping of regional permeability distribution and thickness.The principal conclusions of the study are that reservoirs with sufficient porosity, permeability and volume for conventional oil and gas production exist within the Sydney Basin. Best reservoir quality occurs in quartzose sandstones of the Narrabeen Group in the southwestern part of the basin. Potential reservoir sandstones are up to 20 m thick, have permeabilities in the 10- 1000 md range and porosity between 10 and 18 per cent. Calibration and testing of the visual estimation technique allowed accurate and efficient continuous recording and mapping of porosity and permeability, and this technique may have much wider application for the petroleum industry.

Overpressure Identification Using The Eaton Method on The Gumai Formation of Geragai Graben, Jambi Sub Basin

2020 ◽  
Author(s):  
A. O. Marnila
Keyword(s):  
Pressure Data ◽  
Stratigraphic Sequence ◽  
Fine Grained ◽  
Marine Sedimentation ◽  
Plot Analysis ◽  
Significant Reversal ◽  
Porosity And Permeability ◽  
Upper Level ◽  
Type Data ◽  
Fine Grained Sand

Geragai graben is located in the South Sumatera Basin. It was formed by mega sequence tectonic process with various stratigraphic sequence from land and marine sedimentation. One of the overpressure indication zones in the Geragai graben is in the Gumai Formation, where the sedimentation is dominated by fine grained sand and shale with low porosity and permeability. The aim of the study is to localize the overpressure zone and to analyze the overpressure mechanism on the Gumai Formation. The Eaton method was used to determine pore pressure value using wireline log data, pressure data (RFT/FIT), and well report. The significant reversal of sonic and porosity log is indicating an overpressure presence. The cross-plot analysis of velocity vs density and fluid type data from well reports were used to analyze the causes of overpressure in the Gumai Formation. The overpressure in Gumai Formation of Geragai graben is divided into two zones, they are in the upper level and lower level of the Gumai Formation. Low overpressure have occurred in the Upper Gumai Formation and mild overpressure on the Lower Gumai Formation. Based on the analyzed data, it could be predicted, that the overpressure mechanism in the Upper Gumai Formation might have been caused by a hydrocarbon buoyancy, whereas in the Lower Gumai Formation, might have been caused by disequilibrium compaction as a result of massive shale sequence.

Sign in / Sign up

Export Citation Format

Share Document