Insight into Heterogeneous Calcite Cementation of Turbidite Channel-Fills from UAV Photogrammetry

Diagenesis is a key controlling factor on sandstone porosity and permeability. Understanding type, paragenetic sequence and spatial patterns of cements is thus important for assessing sandstone hydrocarbon reservoir properties. In this study Unmanned Aerial Vehicle (UAV) photogrammetry is used to evaluate the shape and spatial distribution of calcite concretions developed within the sand-prone fill of a turbidite channel. The studied channel-fill is entrenched into hemipelagic marlstones and include a lower conglomeratic sandstone loaded with marlstone rip-ups and an upper fill featuring a range of turbidite bed types, which, up-section and off the channel axis, are progressively finer grained and less amalgamated. Concretion shape analysis highlighted a continuum of equant to oblate shapes with flat-lying major axes and a cumulative volume fraction of ca. 22%. Equant to sub-equant concretions are ubiquitous and occur at different heights within beds, often developing around marlstone rip-ups. Conversely, elongated concretions are either strata-bound concretions or completely cemented beds which become volumetrically dominant up section and off the channel axis. The interparticle pore-space of concretions represents on average ca. 22% and is tightly filled by poikilotopic and blocky calcite cement precipitated near to maximum burial depth, whereas host sandstones lack calcite cements and show smectite clay cement and an average preserved porosity of ca. 15%. The oxygen and carbon isotopes of calcite cements point to the marlstone as the main source of carbonate ions, suggesting concretions developed during burial by either diffusion from rip-ups and mud caps or recrystallization of, matrix micrite. Results suggest that the process by which the carbonate-rich component was eroded from the substrate and trapped within the channel-fill is a key control on spatial distribution of calcite concretions, likely to reflect on spatial variability of reservoir properties.

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Impact of Diagenesis on the Reservoir Properties of the Cretaceous Sandstones in the Southern Bredasdorp Basin, Offshore South Africa

Minerals ◽

10.3390/min10090757 ◽

2020 ◽

Vol 10 (9) ◽

pp. 757

Author(s):

Temitope Love Baiyegunhi ◽

Kuiwu Liu ◽

Oswald Gwavava ◽

Christopher Baiyegunhi

Keyword(s):

Oil And Gas ◽

Gas Production ◽

Reservoir Quality ◽

Reservoir Properties ◽

Oil And Gas Production ◽

Thin Sections ◽

Hydrocarbon Reservoir ◽

Porosity And Permeability ◽

The Impact

The Cretaceous sandstone in the Bredasdorp Basin is an essential potential hydrocarbon reservoir. In spite of its importance as a reservoir, the impact of diagenesis on the reservoir quality of the sandstones is almost unknown. This study is undertaken to investigate the impact of digenesis on reservoir quality as it pertains to oil and gas production in the basin. The diagenetic characterization of the reservoir is based on XRF, XRD SEM + EDX, and petrographic studies of 106 thin sections of sandstones from exploration wells E-AH1, E-AJ1, E-BA1, E-BB1 and E-D3 in the basin. The main diagenetic processes that have affected the reservoir quality of the sandstones are cementation by authigenic clay, carbonate and silica, growth of authigenic glauconite, dissolution of minerals and load compaction. Based on the framework grain–cement relationships, precipitation of the early calcite cement was either accompanied or followed up by the development of partial pore-lining and pore-filling clay cements, particularly illite. This clay acts as pore choking cement, which reduces porosity and permeability of the reservoir rocks. The scattered plots of porosity and permeability versus cement + clays show good inverse correlations, suggesting that the reservoir quality is mainly controlled by cementation and authigenic clays.

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Diagenetic Clay Minerals and Their Controls on Reservoir Properties of the Shahbazpur Gas Field (Bengal Basin, Bangladesh)

Geosciences ◽

10.3390/geosciences10070250 ◽

2020 ◽

Vol 10 (7) ◽

pp. 250

Author(s):

Md Nahidul Hasan ◽

Rumana Yeasmin ◽

M. Julleh Jalalur Rahman ◽

Sally Potter-McIntyre

Keyword(s):

Clay Minerals ◽

Clay Mineralogy ◽

Bengal Basin ◽

Burial Depth ◽

Reservoir Properties ◽

Electron Microscopic ◽

Gas Field ◽

Kübler Index ◽

Porosity And Permeability ◽

Index Value

Clay mineralogy and diagenesis affect the reservoir quality of the Neogene Surma Group in the Hatiya trough of Bengal Basin, Bangladesh. X-ray diffraction and scanning electron microscopic analyses of diagenetic clay minerals from Shahbazpur#2 well reveal that on average illite is the dominant clay mineral (50%), followed by chlorite (24%), kaolinite (23%) and smectite (2.50%). The absence of smectite at Core-2 (3259.80 m to 3269 m) results from the total transformation of smectite to illite owing to burial depth and high K–feldspar. The diagenetic changes are a result of chemical processes such as cementation, chlorite authigenesis, dissolution, alteration and replacement that have significantly affected the reservoir properties. Cementation plays an important role in reducing reservoir properties with pore and fracture filling cement. The relative percentage of illite and smectite minerals (>90% illite in I/S mixed layer) and Kübler index value (0.34° to 0.76° Δ2θ) indicate a diagenetic zone with subsurface temperatures of 120–180 °C in the studied samples. The temperature range determined using clay percentages and the Kübler index as a geothermometer is supported by observed diagenetic features such as quartz overgrowths, smectite to illite transformations and chlorite coatings. The diagenetic features cause variable reservoir porosity and permeability that are critical in planning exploration and development programs of this field or analog fields across the Bengal Basin.

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Secondary alterations of deep buried Lower Carboniferous terrigenous rocks in some areas of the Dnieper-Donets basin

Geology Geography Ecology ◽

10.26565/2410-7360-2019-51-07 ◽

2019 ◽

Keyword(s):

Influencing Factors ◽

Pore Space ◽

Great Depth ◽

Donets Basin ◽

Reservoir Properties ◽

Reservoir Rocks ◽

Terrigenous Rocks ◽

Porosity And Permeability ◽

Hydrocarbon Deposits ◽

Epigenetic Processes

Problematics. Due to the ambiguous understanding of the nature and void space distribution within reservoir rocks, prediction of prospective deep buried and low permeable reservoirs becomes more uncertain. There are many factors influencing on the pore space, such as primary rock composition, hydrogeological regime, tectonic processes, geological time, epigenetic processes etc. Moreover, in explanation of different factors the influence of secondary reservoirs formation, systematization problems become more essential. Either, it is important to identify ‘working’ conditions of influencing factors to make the prediction of hydrocarbon deposits at great depth more certain. Finding universal criteria of prospective secondary reservoir rocks identification will allow us to enhance the discovery rate of deep buried hydrocarbon deposits. Analysis of previous studies. Many researches were devoted to epigenetic processes in the second part of XXth century. There were described major secondary alterations which may occur at great depth. Recent publications showed the expansion of previous knowledge about epigenetic processes and their influence on the secondary deep buried reservoir formation. Some scientists state that major influencing factors on reservoir quality are tectonic and primary mineral composition, others bring epigenetic imposed processes to the top of influencing factors. Purpose. The purpose of the research is to study secondary alterations and find possible zonation based on the alteration intensity of Carboniferous (Viséan and Serpukhovian) rocks within Central part of the Dnieper-Donets basin. Methods. During this research we studied 43 thin sections of Carboniferous sandstones from cores of Central part of the Dnieper-Donets basin, using polarizing microscope. Alteration stage analyses were used for determination of mineral sequence transformations. Results. Carboniferous (Viséan and Serpukhovian) sandstones discovered by deep wells within Solokhivsko-Dykanskyi and Berezivsko-Kotelevskyi archs in Central part of the Dnieper-Donets depression have been studied. Microscopic studies have shown widespread development of imposed epigenetic alterations in terrigenous rocks. The involvement of laboratory evaluation of porosity and permeability, as well as the values of formation temperatures, allowed us to determine the main trends of secondary processes effect on reservoir properties of rocks. It is shown that the development of secondary microfracturing, kaolinitization and sideritization increases the value of porosity and permeability. Dissolution, regeneration and redeposition of quartz are accompanied by calcitization and lead to the significant decrease of the reservoir properties of terrigenous rocks and formation of secondary epigenetic seals. Sideritization facilitates the development of secondary reservoirs at great depth, meanwhile calcitization leads to decrease of the pore space. Bitumoids and pyrite presence may be the evidence of hydrocarbon migration process. Combination of the research results with thermobaric data retrieved directly from borehole measurements as well as theoretically calculated on Bilske gas condensate field shows that formation of epigenetic seal in the temperature interval of 110-120 °C is caused by quartz dissolution and intensive calcitization of terrigenous rocks. Consequently, secondary reservoir rocks below the epigenetic seal have local spreading caused by microfracturing, sideritization and calcitization. Specific secondary sandy reservoirs of Berezivske gas condensate field are located within 110 and 120 °C isotherm. They occurred in acid environment leading to dissolution of calcite cement and intense sandstone kaolinitization. Such favorable conditions for secondary porosity formation may occur as a result of possible tectonic movements inversion which triggered the development of regressive epigenesis.

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Carbonate Diagenesis in a Sequence Stratigraphic Framework; Case study from Miocene Dam Formation, Eastern Saudi Arabia

10.5194/egusphere-egu2020-21365 ◽

2020 ◽

Author(s):

Moaz Salih ◽

Osman Abdullatif ◽

Khalid Al-Ramadan ◽

Mazin Bashri

Keyword(s):

Saudi Arabia ◽

Arabian Plate ◽

Sequence Stratigraphic ◽

Hydrocarbon Reservoir ◽

Diagenetic Processes ◽

Porosity And Permeability ◽

Thin Section Petrography ◽

Calcite Cement ◽

Sequence Boundaries ◽

Analytical Tools

The Miocene Dam Formation in the Al-Lidam area of Eastern Saudi Arabia consists of a succession&#160;of mixed siliciclastic-carbonate sequences that were deposited during Miocene (Burdigalian)&#160;times. Stratigraphic equivalents of the Dam Formation occur as hydrocarbon reservoir intervals in&#160;the Arabian Plate. Reservoir quality of carbonate rocks is controlled by a combination of&#160;depositional setting and post-depositional diagenetic factors.&#160;In this study, fifteen lithofacies were identified as they were deposited on a low angle dipping&#160;carbonate ramp, under supratidal, beach, intertidal and shallow subtidal conditions. Carbonate&#160;diagenesis has been examined using: thin-section petrography, SEM, XRD and&#160;cathodoluminescence. These analytical tools have shown that the intertidal lithofacies are&#160;influenced by extensive meteoric dissolution and minor cementation. Marine diagenesis was&#160;restricted to beach grainstone and subtidal lithofacies, in the form of aragonite and high magnesium&#160;calcite cement. Shallow burial conditions were inferred by grain contacts represented by point,&#160;suture and concavo-convex contacts. Mimetic dolomitization for the whole succession was also&#160;observed. Three fourth - order, shallowing upward sequences were identified in the study area, and&#160;they are separated by two sequence boundaries. A clear relation between sequence surfaces and&#160;diagenetic processes was observed; meteoric diagenesis and dolomitization increases upwards in&#160;each sequence. Porosity and permeability measurements have shown that the highest values are&#160;associated with the HST of each sequence, followed by the TST and the LST. The results of this&#160;study can help in understanding of diagenetic processes, and consequently in developing better&#160;and more accurate predictions of the porosity and permeability distribution within hydrocarbon&#160;reservoirs.&#160;

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Diagenetic peculiarities of potential Lower Jurassic reservoir sandstones, Troms 1 area, Off Northern Norway, and their tectonic significance

Clay Minerals ◽

10.1180/claymin.1986.021.4.09 ◽

1986 ◽

Vol 21 (4) ◽

pp. 565-584 ◽

Cited By ~ 7

Author(s):

P. Riches ◽

I. Traub-Sobott ◽

W. Zimmerle ◽

U. Zinkernagel

Keyword(s):

Pore Space ◽

High Energy ◽

Lower Jurassic ◽

Burial Depth ◽

Secondary Porosity ◽

Reservoir Rocks ◽

Diagenetic Alteration ◽

Potential Reservoir ◽

Porosity And Permeability ◽

Reservoir Sandstones

AbstractIn the Troms 1 area, sediments of Early to Middle Jurassic age, ranging from alluvial plain deposits at the base, passing through coastal plain/tidal flat sediments up into high-energy nearshore shallow-marine sands, mark a transgression. The sandstones, classified as mineralogically and texturally mature quartz-arenites, are potential reservoir rocks in the eastern part of the area. The apparent supermaturity, however, is of secondary origin because unstable detrital components were dissolved during diagenesis. The succession of complex diagenetic processes was: (i) mechanical compaction and simultaneous pressure solution, (ii) partial dissolution with corrosion of detrital quartz and dissolution of unstable fragments, (iii) silica cementation, (iv) calcite cementation, (v) partial carbonate dissolution, (vi) kaolinite/Fe-carbonate cementation in the remaining pore space. Porosity and permeability of the sandstones are controlled by the degree of silicification and by dissolution processes. Two dissolution stages led to partial ‘skeletonization’ of the detrital framework and to elimination of unstable detrital grains. The first stage was a basic process leading to corrosion of detrital quartz and creating transitory secondary porosity; the second stage was acidic leading to the present preserved secondary porosity. Diagenetic dissolution channels formed. The degree of diagenetic alteration was much higher than normally observed in sandstones of such burial depth. Hydrothermal solutions rising from deep-seated faults may have led to this unusual alteration and triggered a rift-related type of complex diagenesis.

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Diagenesis of Upper Jurassic sandstones of the Blokelv-1 core in the Jameson Land Basin, East Greenland

Geological Survey of Denmark and Greenland Bulletin ◽

10.34194/geusb.v42.4310 ◽

2018 ◽

pp. 65-84

Author(s):

Mette Olivarius ◽

Rikke Weibel ◽

Niels H. Schovsbo ◽

Dan Olsen ◽

Claus Kjøller

Keyword(s):

Upper Jurassic ◽

Late Eocene ◽

Petrographic Analysis ◽

Burial Depth ◽

Early Eocene ◽

X Ray Diffraction ◽

X Ray ◽

Lower Porosity ◽

Porosity And Permeability ◽

Calcite Cement

Petrographic analysis combined with X-ray diffraction are used to identify the diagenetic changes that have affected the porosity and permeability of gravity-flow sandstones of the Oxfordian–Volgian Hareelv Formation in the cored Blokelv-1 borehole in Jameson Land. Kaolinite replacement of albite grains probably occurred early after deposition and microquartz coatings formed under shallow burial. At deeper burial, illite and quartz formed from kaolinite and K-feldspar. Pervasive ankerite cement formed in the finest grained sandstones and may have formed at the expense of early calcite cement. Quartz overgrowths are volumetrically small, partly due to inhibition by microquartz coatings and partly due to limited residence time during deep burial. The succession reached the maximum burial depth of c. 2.8 km during the late Eocene. Basaltic material was intruded into the sediments during the early Eocene and the enhanced heat flow accelerated diagenesis in the close vicinity of the intrusions, which have thicknesses of up to 2 m. Most of the sandstones have porosities between 14.4 and 25.7% and permeabilities between 0.4 and 411.9 mD; this variation resulted from a combination of microquartz coatings and clay minerals. However, the intrusion-influenced sandstones and the ankerite-cemented sandstones have lower porosity and permeability.

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Macroprobe Mode for the Study of Segregation in Steels

Proceedings, annual meeting, Electron Microscopy Society of America ◽

10.1017/s0424820100134909 ◽

1990 ◽

Vol 48 (2) ◽

pp. 260-261

Author(s):

Auclair Gilles ◽

Benoit Danièle

Keyword(s):

Mechanical Properties ◽

Spatial Distribution ◽

High Performance ◽

Volume Fraction ◽

Sheet Steel ◽

Acquisition Time ◽

Chemical Information ◽

X Ray ◽

Accurate Quantitative Analysis ◽

Optical Micrographs

During these last 10 years, high performance correction procedures have been developed for classical EPMA, and it is nowadays possible to obtain accurate quantitative analysis even for soft X-ray radiations. It is also possible to perform EPMA by adapting this accurate quantitative procedures to unusual applications such as the measurement of the segregation on wide areas in as-cast and sheet steel products.The main objection for analysis of segregation in steel by means of a line-scan mode is that it requires a very heavy sampling plan to make sure that the most significant points are analyzed. Moreover only local chemical information is obtained whereas mechanical properties are also dependant on the volume fraction and the spatial distribution of highly segregated zones. For these reasons we have chosen to systematically acquire X-ray calibrated mappings which give pictures similar to optical micrographs. Although mapping requires lengthy acquisition time there is a corresponding increase in the information given by image anlysis.

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

Netherlands Journal of Geosciences – Geologie en Mijnbouw ◽

10.1017/njg.2016.28 ◽

2016 ◽

Vol 95 (3) ◽

pp. 253-268 ◽

Cited By ~ 2

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.

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Estimation of porosity, fluid bulk modulus, and stiff-pore volume fraction using a multi-trace Bayesian AVO petrophysics inversion in multi-porosity reservoirs

Geophysics ◽

10.1190/geo2021-0029.1 ◽

2021 ◽

pp. 1-101

Author(s):

Kun Li ◽

Xingyao Yin ◽

Zhaoyun Zong ◽

Dario Grana

Keyword(s):

Bulk Modulus ◽

Pore Volume ◽

Elastic Moduli ◽

Wave Reflection ◽

Volume Fraction ◽

Inversion Method ◽

Reservoir Properties ◽

Pore Volume Fraction ◽

Pp Wave ◽

Matrix Shear

The estimation of petrophysical and fluid-filling properties of subsurface reservoirs from seismic data is a crucial component of reservoir characterization. Seismic amplitude variation with offset (AVO) inversion driven by rock physics is an effective approach to characterize reservoir properties. Generally, PP-wave reflection coefficients, elastic moduli and petrophysical parameters are nonlinearly coupled, especially in the multiple type pore-space reservoirs, which makes seismic AVO petrophysics inversion ill-posed. We propose a new approach that combines Biot-Gassmanns poro-elasticity theory with Russells linear AVO approximation, to estimate the reservoir properties including elastic moduli and petrophysical parameters based on multi-trace probabilistic AVO inversion algorithm. We first derive a novel PP-wave reflection coefficient formulation in terms of porosity, stiff-pore volume fraction, rock matrix shear modulus, and fluid bulk modulus to incorporate the effect of pore structures on elastic moduli by considering the soft and stiff pores with different aspect ratios in sandstone reservoirs. Through the analysis of the four types of PP-wave reflection coefficients, the approximation accuracy and inversion feasibility of the derived formulation are verified. The proposed stochastic inversion method aims to predict the posterior probability density function in a Bayesian setting according to a prior Laplace distribution with vertical correlation and prior Gaussian distribution with lateral correlation of model parameters. A Metropolis-Hastings stochastic sampling algorithm with multiple Markov chains is developed to simulate the posterior models of porosity, stiff-pore volume fraction, rock-matrix shear modulus, and fluid bulk modulus from seismic AVO gathers. The applicability and validity of the proposed inversion method is illustrated with synthetic examples and a real data application.

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Joint Application of Diagenetic, Petrophysical and Geomechanical Data for Selecting Hydraulic Fracturing Candidate Zone

International Journal of Petroleum Technology ◽

10.15377/2409-787x.2021.08.5 ◽

2021 ◽

Vol 8 ◽

pp. 55-79

Author(s):

E. Bakhshi ◽

A. Shahrabadi ◽

N. Golsanami ◽

Sh. Seyedsajadi ◽

X. Liu ◽

...

Keyword(s):

Hydraulic Fracturing ◽

Pore Pressure ◽

Earth Model ◽

Reservoir Properties ◽

Stress Regime ◽

Geomechanical Properties ◽

Hydrocarbon Reservoir ◽

Diagenetic Processes ◽

Mechanical Earth Model ◽

New Equation

The more comprehensive information on the reservoir properties will help to better plan drilling and design production. Herein, diagenetic processes and geomechanical properties are notable parameters that determine reservoir quality. Recognizing the geomechanical properties of the reservoir as well as building a mechanical earth model play a strong role in the hydrocarbon reservoir life cycle and are key factors in analyzing wellbore instability, drilling operation optimization, and hydraulic fracturing designing operation. Therefore, the present study focuses on selecting the candidate zone for hydraulic fracturing through a novel approach that simultaneously considers the diagenetic, petrophysical, and geomechanical properties. The diagenetic processes were analyzed to determine the porosity types in the reservoir. After that, based on the laboratory test results for estimating reservoir petrophysical parameters, the zones with suitable reservoir properties were selected. Moreover, based on the reservoir geomechanical parameters and the constructed mechanical earth model, the best zones were selected for hydraulic fracturing operation in one of the Iranian fractured carbonate reservoirs. Finally, a new empirical equation for estimating pore pressure in nine zones of the studied well was developed. This equation provides a more precise estimation of stress profiles and thus leads to more accurate decision-making for candidate zone selection. Based on the results, vuggy porosity was the best porosity type, and zones C2, E2 and G2, having suitable values of porosity, permeability, and water saturation, showed good reservoir properties. Therefore, zone E2 and G2 were chosen as the candidate for hydraulic fracturing simulation based on their E (Young’s modulus) and ν (Poisson’s ratio) values. Based on the mechanical earth model and changes in the acoustic data versus depth, a new equation is introduced for calculating the pore pressure in the studied reservoir. According to the new equation, the dominant stress regime in the whole well, especially in the candidate zones, is SigHmax>SigV>Sighmin, while according to the pore pressure equation presented in the literature, the dominant stress regime in the studied well turns out to be SigHmax>Sighmin>SigV.

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