Facies, diagenesis and secondary porosity of a Miocene reefal platform of Central Luconia, Malaysia

Abstract. The assessment of diagenetic overprint on microstructural and geochemical data gained from fossil archives is of fundamental importance for understanding palaeoenvironments. The correct reconstruction of past environmental dynamics is only possible when pristine skeletons are unequivocally distinguished from altered skeletal elements. Our previous studies show (i) that replacement of biogenic carbonate by inorganic calcite occurs via an interface-coupled dissolution–reprecipitation mechanism. (ii) A comprehensive understanding of alteration of the biogenic skeleton is only given when structural changes are assessed on both, the micrometre as well as on the nanometre scale.In the present contribution we investigate experimental hydrothermal alteration of six different modern biogenic carbonate materials to (i) assess their potential for withstanding diagenetic overprint and to (ii) find characteristics for the preservation of their microstructure in the fossil record. Experiments were performed at 175 °C with a 100 mM NaCl + 10 mM MgCl2 alteration solution and lasted for up to 35 days. For each type of microstructure we (i) examine the evolution of biogenic carbonate replacement by inorganic calcite, (ii) highlight different stages of inorganic carbonate formation, (iii) explore microstructural changes at different degrees of alteration, and (iv) perform a statistical evaluation of microstructural data to highlight changes in crystallite size between the pristine and the altered skeletons.We find that alteration from biogenic aragonite to inorganic calcite proceeds along pathways where the fluid enters the material. It is fastest in hard tissues with an existing primary porosity and a biopolymer fabric within the skeleton that consists of a network of fibrils. The slowest alteration kinetics occurs when biogenic nacreous aragonite is replaced by inorganic calcite, irrespective of the mode of assembly of nacre tablets. For all investigated biogenic carbonates we distinguish the following intermediate stages of alteration: (i) decomposition of biopolymers and the associated formation of secondary porosity, (ii) homoepitactic overgrowth with preservation of the original phase leading to amalgamation of neighbouring mineral units (i.e. recrystallization by grain growth eliminating grain boundaries), (iii) deletion of the original microstructure, however, at first, under retention of the original mineralogical phase, and (iv) replacement of both, the pristine microstructure and original phase with the newly formed abiogenic product.At the alteration front we find between newly formed calcite and reworked biogenic aragonite the formation of metastable Mg-rich carbonates with a calcite-type structure and compositions ranging from dolomitic to about 80 mol % magnesite. This high-Mg calcite seam shifts with the alteration front when the latter is displaced within the unaltered biogenic aragonite. For all investigated biocarbonate hard tissues we observe the destruction of the microstructure first, and, in a second step, the replacement of the original with the newly formed phase.

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Porosity evolution of high-quality reservoirs in deep Palaeogene lacustrine carbonate rocks in the central Bohai Sea

Energy Exploration & Exploitation ◽

10.1177/0144598717753621 ◽

2018 ◽

Vol 36 (5) ◽

pp. 1136-1156 ◽

Cited By ~ 1

Author(s):

Yuanhua Qing ◽

Zhengxiang Lü ◽

Xiandong Wang ◽

Xiuzhang Song ◽

Shunli Zhang ◽

...

Keyword(s):

Bohai Sea ◽

Oil And Gas ◽

Early Stage ◽

Reservoir Rock ◽

Secondary Porosity ◽

Authigenic Minerals ◽

Porosity Evolution ◽

Lacustrine Carbonate ◽

Reservoir Porosity ◽

Pore Lining

The oil and gas in the Palaeogene lacustrine carbonate rock reservoirs in the Bohai Sea accumulated during several periods. The reservoir porosity formed during each period affected the degree of accumulation that occurred. In this paper, the percentages of particles, authigenic minerals and pores in the reservoir bed were calculated with the statistical method of microstructure analysis. The formation time was determined with an isotopic analysis of the authigenic carbonate minerals and the homogenization temperature of the gas–liquid inclusions. The percentages of the primary intergranular pores that formed during the different stages were recovered based on the compaction features both before and after the formation of the major authigenic minerals. The evolution of porosity was thus described quantitatively and chronologically, employing the percentages of the residual primary intergranular pores, visceral cavity pores and dissolved pores at the different burial depths. The results indicate that in the initial sediments of the reservoir rock, the primary intergranular porosity was 32.4%. During the early burial stage, the total reservoir porosity increased by up to 46.9%, due to the addition of another type of primary pore, namely visceral cavity pores, which were generated from the decomposition of bioclasts. During the late, deep burial stage, the compaction reduced only 8.2% of the porosity, due to the support of the pore-lining dolomite precipitating during the early stage. Authigenic minerals occupied 12.6% of the porosity, and the dissolution created the secondary porosity by 3.8%. Good preservation of the visceral cavity pores and the growth of the pore-lining dolomites during the early stages are the major factors leading to the high reservoir porosity. The quantitative and chronological characteristics of the reservoir porosity evolution could be described accurately. The prediction of reservoir beds can be better guided than in previously reported methods by applying high resolution microscopic quantitative analysis technology and authigenic mineral timing analysis technology.

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Linking Depositional Environments and Diagenetic Processes to Porosity Evolution and destruction in the Arab Formation reservoirs, Offshore oilfields of Qatar

University of the Future: Re-Imagining Research and Higher Education ◽

10.29117/quarfe.2020.0043 ◽

2020 ◽

Author(s):

Fadhil N. Sadooni ◽

Hamad Al-Saad Al-Kuwari ◽

Ahmad Sakhaee-Pour ◽

Wael S. Matter

Keyword(s):

Depositional Environments ◽

Oil Reservoir ◽

Secondary Porosity ◽

Future Directions ◽

Thin Sections ◽

Intergranular Porosity ◽

Porosity Evolution ◽

Diagenetic Processes ◽

Exploration And Production ◽

The Impact

Introduction: The Jurassic Arab Formation is the main oil reservoir in Qatar. The Formation consists of a succession of limestone, dolomite, and anhydrite. Materials and methods: A multi-proxy approach has been used to study the Formation. This approach is based on core analysis, thin sections, and log data in selected wells in Qatar. Results: The reservoir has been divided into a set of distinctive petrophysical units. The Arab Formation consists of cyclic sediments of oolitic grainstone/packstone, foraminifera-bearing packstone-wackestone, lagoonal mudstone and dolomite, alternating with anhydrite. The sediments underwent a series of diagenetic processes such as leaching, micritization, cementation, dolomitization and fracturing. The impact of these diagenetic processes on the different depositional fabrics created a complex porosity system. So, in some cases there is preserved depositional porosity such as the intergranular porosity in the oolitic grainstone, but in other cases, diagenetic cementation blocked the same pores and eventually destroyed them. In other cases, diagenesis improved the texture of non-porous depositional texture such as mudstone through incipient dolomitization creating inter-crystalline porosity. Dissolution created vugs and void secondary porosity in otherwise non-porous foraminiferal wackestone and packstone. Therefore, creating a matrix of depositional fabrics versus diagenetic processes enabled the identification of different situations in which porosity was either created or destroyed. Future Directions: By correlating the collected petrographic data with logs, it will become possible to identify certain “facio-diagenetic” signatures on logs which will be very useful in both exploration and production. Studying the micro and nano-porosity will provide a better understanding of the evolution and destruction of its porosity system.

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Petrophysical Properties and Digenetic Evolution of Shuaiba Formation in Nasiriyah Oil Field, Southern Iraq

Iraqi Journal of Science ◽

10.24996/ijs.2021.62.12.19 ◽

2021 ◽

pp. 4810-4818

Author(s):

Marwah H. Khudhair

Keyword(s):

Gamma Ray ◽

Water Saturation ◽

Middle Part ◽

Effective Porosity ◽

Oil Field ◽

Neutron Density ◽

Petrophysical Properties ◽

Secondary Porosity ◽

Primary Porosity ◽

Gamma Ray Log

Shuaiba Formation is a carbonate succession deposited within Aptian Sequences. This research deals with the petrophysical and reservoir characterizations characteristics of the interval of interest in five wells of the Nasiriyah oil field. The petrophysical properties were determined by using different types of well logs, such as electric logs (LLS, LLD, MFSL), porosity logs (neutron, density, sonic), as well as gamma ray log. The studied sequence was mostly affected by dolomitization, which changed the lithology of the formation to dolostone and enhanced the secondary porosity that replaced the primary porosity. Depending on gamma ray log response and the shale volume, the formation is classified into three zones. These zones are A, B, and C, each can be split into three rock intervals in respect to the bulk porosity measurements. The resulted porosity intervals are: (I) High to medium effective porosity, (II) High to medium inactive porosity, and (III) Low or non-porosity intervals. In relevance to porosity, resistivity, and water saturation points of view, there are two main reservoir horizon intervals within Shuaiba Formation. Both horizons appear in the middle part of the formation, being located within the wells Ns-1, 2, and 3. These intervals are attributed to high to medium effective porosity, low shale content, and high values of the deep resistivity logs. The second horizon appears clearly in Ns-2 well only.

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Fractal Scaling of Secondary Porosity in Karstic Exposures of the Edwards Aquifer

Sinkholes and the Engineering and Environmental Impacts of Karst ◽

10.1061/40796(177)19 ◽

2005 ◽

Cited By ~ 3

Author(s):

Robert E. Mace ◽

Randall A. Marrett ◽

Susan D. Hovorka

Keyword(s):

Edwards Aquifer ◽

Secondary Porosity ◽

Fractal Scaling

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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

10.29118/ipa21-g-15 ◽

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.

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