DETRITAL AND AUTHIGENIC MINERALOGY OF THE PRETTY HILL FORMATION IN THE PENOLA TROUGH, OTWAY BASIN: IMPLICATIONS FOR FUTURE EXPLORATION AND PRODUCTION

1995 ◽  
Vol 35 (1) ◽  
pp. 538 ◽  
Author(s):  
B. M. Little ◽  
S. E. Phillips
Keyword(s):  
Reservoir Quality ◽  
Secondary Porosity ◽  
Water Contact ◽  
Thin Sections ◽  
Authigenic Minerals ◽  
Wide Range ◽  
Resistivity Logs ◽  
Exploration And Production ◽  
Reservoir Sandstones ◽  
The Impact

The Pretty Hill Formation in the Penola Trough is a productive gas reservoir in the Katnook, Ladbroke Grove and Haselgrove fields. Thin sections, X-ray diffraction, scanning electron micros­copy and electron microprobe analyses have been used to characterise the mineralogy of core samples from eight wells. The reservoir sandstones are typically fine to medium grained, moderately sorted feldspathic litharenites. Framework grains comprise detrital quartz, feldspars (albite, microcline and anorthite), lithics (dominantly volcanic), mica and accessory minerals. Authigenic minerals of chlorite, laumontite, carbonate, quartz, feldspar, sphene, anatase, glaucony and illite are present in all wells. Kaolinite is restricted to Ladbroke Grove-1. Chlorite, laumontite and carbonate are volumetrically the most important authigenic minerals.There is a wide range in core plug porosity (one to 23 per cent) and permeability (10"3to 103 md) in the reservoir sandstones. In samples with high per­centages of authigenic clays microporosity is im­portant. Regional trends indicate reservoir quality decreases with increasing depth but superimposed on this trend is the influence of the detrital and authigenic mineralogy. Cleaner, coarser sublitharenites and subarkoses have good reservoir char­acteristics but where lithics concentrate in the finer feldspathic litharenites and litharenites deformation of these ductile grains has limited porosity and permeability. Authigenic minerals have both reduced and enhanced reservoir quality. Chlo­rite rims with associated microporosity have decreased the impact of mechanical compaction and inhibited silicification. Pore filling cements of laumontite and carbonate have occluded intergranular pores and replaced grains. Secondary porosity produced by the dissolution of these cements in the gas zones has significantly improved reservoir quality.Other information gained from the mineralogical study could influence future exploration and production. Lack of contrast on resistivity logs between gas and water zones is not due to the mineralogy of the Pretty Hill Formation. However, the restriction of early diagenetic laumontite to the water zones of gas producing wells does indicate the location of the gas-water contact. Laumontite was dissolved from the gas zone by an increase in C02 prior to hydrocarbon migration. Use of acids to enhance permeability in the Pretty Hill Formation should take into account the probable formation damage caused by reactions with the clays. Kaolin- ite could dissolve to produce a silica gel and the high Fe3+ content of the chlorite will result in a gel unless iron chelators are used in the mud acid. The depositional environment of the Pretty Hill Forma­tion has historically been interpreted as braided fluvial stream deposits interfingering with finer grained lacustrine shales and siltstone. However, this model can not explain the presence of glaucony grains, unless the glaucony has been reworked, but there is no unequivocal evidence to support this hypothesis.

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

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.

Role of fracturing and regional tectonic structures on secondary porosity generation in a CO2 storage plant: Hontomin pilot-plant (Spain)

2020 ◽  
Author(s):  
Adrià Ramos ◽  
José F. Mediato ◽  
Raúl Pérez-López ◽  
Miguel A. Rodríguez-Pascua ◽  
Roberto Martínez-Orío ◽  
...  
Keyword(s):  
Pilot Plant ◽  
Lateral Displacement ◽  
Co2 Storage ◽  
Fracture Pattern ◽  
Test Facility ◽  
Fracture System ◽  
Secondary Porosity ◽  
Wide Range ◽  
The Impact

<p>The long-term managing from the geological hazard point of view of the Hontomín onshore pilot-plant for CO<sub>2 </sub>storage, located in Spain and recognized as the first and only key-test facility in Europe, is one of the main objectives stated in the ENOS European project. This project is led and funded by the European Network of Excellence on the Geological Storage of CO<sub>2</sub> (CO<sub>2</sub>GeoNet).</p><p>The complex geological emplacement of the Hontomín Carbon capture and storage plant is considered rather relevant to analyse the impact of fracturing and both local and regional strain field on the reservoir parameters. The reservoir of Hontomín pilot-plant is formed by highly fractured Middle Jurassic dolomites with associated secondary porosity. This parameter is one of the main concerns when managing CO<sub>2</sub> storage and monitoring.</p><p>In order to characterize the fracture pattern and its implications on a proper CO<sub>2</sub> monitoring, we characterized the surface structural elements through the study area and their relationship with fractures affecting the reservoir porosity. The methodology followed in this work is mainly based on detailed geological mapping (field work complimented with orthophoto analysis), adding missing information from previous works. This analysis does not increase the cost for long-term monitoring, given that they are low-cost and the results are acquired in a few months.</p><p>The main structural trend in the study area, concerning faults with a wide range of displacement and metric to decametric folds, follows a regional E-W orientation. On the other hand, fractures show two main sets of trends, from NW-SE to NE-SW.</p><p>This fracturing pattern, considered as a conjugate fracture system, corresponds to the tectonic stress recorded in both Mesozoic and Cenozoic sedimentary successions where the Hontomín pilot-plant is placed. Riddle faults formed from a nearby regional right-lateral strike slip fault (Ubierna Fault) are the responsible structures for the fracture system affecting the area and the reservoir. Moreover, this fracturing pattern is in agreement with local to regional active tectonic field from Cenozoic times to present-day, when the Ubierna Fault recorded its maximum right-lateral displacement (15 km).</p><p>Secondary porosity within the reservoir can be produced from this fracture pattern, highly increasing the permeable migration paths for CO<sub>2</sub> migration after the injection. Therefore, we state that a combination between fracture analysis and structural and tectonic study, should be considered as mandatory in the monitoring phases of the CO<sub>2</sub> plume, during and after injection operations.</p>

Redefining Reservoir Architecture of Hydrocarbon-Bearing Ngrayong Formation in Banyu Urip Area:New Insights to Unravel Hidden Potential in East Java Basin

2021 ◽  
Author(s):  
L. O Ahdyar
Keyword(s):  
Deep Water ◽  
Energy Demand ◽  
Carbonate Reservoir ◽  
Reservoir Quality ◽  
New Paradigm ◽  
Thin Sections ◽  
Carbonate Cement ◽  
Reservoir Architecture ◽  
Wide Range ◽  
Clastic Reservoir

Results of Banyu Urip (BU) carbonate exploration, appraisal and development drillings revealed the existence of hydrocarbon-contained in Serravallian deep-water clastic reservoir on top of the primary BU carbonate reservoir. This clastic reservoir is equivalent to the Ngrayong Formation in East Java Basin which is widely known as a mature exploration target and consists of a wide range of depositional environment from fluvio-deltaic (northern part of the Basin) to basin floor (southern part of the basin) with various reservoir quality. However, after a century of exploration activities in East Java Basin, commercial discoveries in the Ngrayong Formation are still considered insignificant (approximately 330 MMboe) (Mazied et al. 2016). This probably due to complex reservoir architecture posted high uncertainty of its reservoir presence, distribution, and quality as well challenging on their dynamic aspects such as un-known hydrocarbon connectivity, un-even contacts and low-deliverability. This paper will present new insights and the potential of Ngrayong clastic opportunity in BU area based on static and dynamic data including BU wells, newly reprocessed 3D seismic data, conventional core and thin sections, as well as integrated geologic and geophysical analyses. Integration of the available dataset suggest the presence of stacked deep water channels and deep water lobes systems. The distribution of stacked channels and lobes seem to be more predictive and widespread, hence providing a better understanding of its reservoir distribution. Furthermore, well data indicates approximately total of 100m net stacked clastic reservoirs consist of mixed carbonate-clastic materials, and have good reservoir pressure connectivity with the carbonate reservoir underneath. This mixed clastic-carbonate system in Ngrayong Formation is diagenetically-altered, and this diagenesis process plays as an important roles in modifying reservoir quality. Although carbonate cement and diagenetic overprint impose challenging reservoir quality prediction, a dissolution creates better reservoir quality, generates excess permeability and produces high flow reservoir. Detail study of reservoir architecture and diagenesis process are critical to better assess volumetric and development opportunity. These key components will open up new paradigm and essential for successful of Ngrayong Formation exploration in East Java Basin in order to contribute to the country’s energy demand.

scholarly journals Experimental study of chlorite authigenesis and influence on porosity maintenance in sandstones

2021 ◽  
Vol 91 (2) ◽  
pp. 197-212
Author(s):  
Dimitrios Charlaftis ◽  
Stuart J. Jones ◽  
Katherine J. Dobson ◽  
Jonathan Crouch ◽  
Sanem Acikalin
Keyword(s):  
Lower Jurassic ◽  
Reservoir Quality ◽  
State Transformation ◽  
Solid State Transformation ◽  
Secondary Porosity ◽  
Sedimentary Sequences ◽  
Wide Range ◽  
The Face ◽  
Reservoir Evolution ◽  
Increasing Temperature

ABSTRACT Chlorite is recognized as a key mineral for preserving reservoir quality in deeply buried sandstones, as chlorite coatings inhibit the nucleation of quartz overgrowths. A limited understanding of the mechanisms and conditions under which these authigenic chlorite coatings form prevents the accurate forward modeling of diagenesis and limits reservoir quality models critical to a wide range of geoscience applications. We present experimental data that show how authigenic chlorite grain coatings preserve porosity in deeply buried sandstone reservoirs, using a series of hydrothermal reactor experiments to simulate quartz cementation and capture the evolving porosity. To simulate reservoir evolution, berthierine-bearing sandstone samples (Lower Jurassic Cook Formation, Oseberg Field, 30/6-17R, Norway) were exposed to a silica-supersaturated Na2CO3 (0.1 M) solution for 72 hours at temperatures of between 100 and 250 °C. Quantification of the temperature-dependent changes in the volume of authigenic chlorite, the thickness and coverage of the clay coatings, and the sample porosity shows increases in chlorite volume (from ∼ 2% to ∼ 14%). This occurs by the transformation, of patchy amorphous berthierine into grain-coating Fe-chlorite cements through a mixture of the solid-state transformation and dissolution–precipitation mechanisms, siderite replacement, and direct precipitation on clay-free surfaces. With increasing temperature, the chlorite coatings increase from ∼ 3.8 μm to ∼ 5.4 μm thick and expand their grain surface coverage from ∼ 28% to ∼ 50%. The face-to-edge and face-to-face foliaceous structure of the clay coatings produced are morphologically similar to those observed in deeply buried sandstones. Only above temperatures of 175 °C is porosity preserved as a consequence of inhibition of quartz overgrowths and the generation of secondary porosity. Our quantitative approach enhances our knowledge regarding the temperature and mineral precursor influence on chlorite-coating authigenesis and therefore provides key insight for chlorite grain coatings for reservoir potential in sedimentary sequences greater than 2.5 km.

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

Minerals ◽  
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.

scholarly journals Diagenesis Processes Impact on Reservoir Quality in Carbonate Yamama Formation /Faihaa Oil Field

2020 ◽  
pp. 92-102
Author(s):  
Mohammed A. Ahmed ◽  
Madhat E. Nasser ◽  
Sameer N. AL Jawad
Keyword(s):  
Oil Field ◽  
Reservoir Quality ◽  
Genetic Classification ◽  
Thin Sections ◽  
Positive Effects ◽  
Diagenetic Processes ◽  
Porosity And Permeability ◽  
Cretaceous Period ◽  
The Impact

The Yamama Formation is a significant reservoir in the southern part of Iraq. This formation consists of limestone deposited throughout the Lower Cretaceous period within main retrogressive depositional series. This study aims to identify the impact of the diagenesis processes on the reservoir’s characteristics (porosity and permeability). Diagenesis processes’ analysis and the identification of Yamama Formation depended on the examination of more than 250 thin sections of the core samples from two wells that were used to determine different diagenetic environments and processes. The three identified diagenetic environments that affected Yamama reservoir were the marine, meteoric and burial environments. Eight diagenetic processes were recognized in Yamama Formation and showed positive and destructive effects on the reservoir quality; Dissolution and fracture had highly positive effects through creating and improving porosity and permeability that led to improving reservoir quality. Cementation and compaction had destructive effects, through reducing porosity and permeability, that led to reducing reservoir quality. Other processes such micritization, dolomitization, bioturbation and neomorphism did not have strong effects on reservoir quality. Based on genetic classification of porosity, most of porosity within Yamama Formation in this field was formed by diagenesis processes, implying that Yamama reservoir is a type of diagenetic reservoir.

scholarly journals Impact of diagenesis on the spatial and temporal distribution of reservoir quality in the Jurassic Arab D and C members, offshore Abu Dhabi oilfield, United Arab Emirates

GeoArabia ◽  
2012 ◽  
Vol 17 (3) ◽  
pp. 17-56
Author(s):  
Sadoon Morad ◽  
Ihsan S. Al-Aasm ◽  
Fadi H. Nader ◽  
Andrea Ceriani ◽  
Marta Gasparrini ◽  
...  
Keyword(s):  
Fluid Inclusion ◽  
United Arab Emirates ◽  
Temporal Distribution ◽  
Abu Dhabi ◽  
Reservoir Quality ◽  
Second Phase ◽  
Burial History ◽  
Burial Diagenesis ◽  
Thin Sections ◽  
The Impact

ABSTRACT This study is based on petrographic examination (optical, scanning electron microscope, cathodo-luminescence, backscattered electron imaging, and fluorescence) of 1,350 thin sections as well as isotopic compositions of carbonates (172 carbon and oxygen and 118 strontium isotopes), microprobe analyses, and fluid inclusion microthermometry of cored Jurassic Arab D and C members from 16 wells in a field from offshore Abu Dhabi, United Arab Emirates. The formation was deposited in a ramp with barrier islands and distal slope setting. Petrographic, stable isotopic and fluid-inclusion analyses have unraveled the impact of diagenesis on reservoir quality of Arab D and C within the framework of depositional facies, sequence stratigraphy, and burial history. Diagenetic processes include cementation by grain rim cement and syntaxial calcite overgrowths, formation of moldic porosity by dissolution of allochems, dolomitization and dolomite cementation, cementation by gypsum and anhydrite, and stylolitization. Partial eogenetic calcite and dolomite cementation has prevented porosity loss in grainstones during burial diagenesis. Dolomitization and sulphate cementation of peritidal mud are suggested to have occurred in an evaporative sabkha setting, whereas dolomitization of subtidal packstones and grainstones was driven by seepage reflux of lagoon brines formed during major falls in relative sea level. Recrystallization of dolomite occurred by hot saline waters (Th 85–100°C; and salinity 14–18 wt% NaCl). Anhydrite and gypsum cements (Th 95–105°C; fluid salinity 16–20 wt% NaCl), were subjected to extensive dissolution, presumably caused by thermal sulfate reduction followed by a major phase of oil emplacement. The last cement recorded was a second phase of anhydrite and gypsum (Th 95–120°C; 16–22 wt% NaCl), which fills fractures associated with faults.

The development and destruction of porosity within Upper Jurassic reservoir sandstones of the Piper and Tartan Fields, Outer Moray Firth, North Sea

Clay Minerals ◽  
1986 ◽  
Vol 21 (4) ◽  
pp. 649-694 ◽  
Author(s):  
S. D. Burley
Keyword(s):  
North Sea ◽  
Ionic Composition ◽  
Upper Jurassic ◽  
High Energy ◽  
Secondary Porosity ◽  
Water Contact ◽  
Moray Firth ◽  
Reservoir Sandstones ◽  
The Individual ◽  
Textural Evidence

AbstractUpper Jurassic Piper Formation sandstones of the Outer Moray Firth Basin, UK North Sea, form the main reservoir for the Piper and Tartan Fields, and are sealed by either the Kimmeridge Clay or Cretaceous marls. The main reservoir sandstones can be broadly considered as stacked coarsening-upward units that accumulated in a predominantly high-energy, shallow marine complex with depositional waters of inferred normal marine salinity, Eh and ionic composition. The amount of porosity and its distribution throughout these sandstones differs between the individual structural entities of the Piper and Tartan Fields. On the Piper structure all the sandstones are highly porous. Oil-zone porosities average 25% and are only slightly reduced in the water zone. Sandstones in the upthrown block of the Tartan structure are also generally porous but porosities are typically reduced to below 20%. Porosities are the most variable in the Tartan downthrown block and in the 15/17-9 well, off-structure Piper, where porous sandstones with between 14 and 18% porosity are associated with highly compacted and cemented sandstones with <5% porosity. Thin-section and SEM textural evidence indicate that much of the porosity in these sandstones is secondary, produced through the dissolution of an intergranular cement that provided support for the detrital framework, was peripherally replacive with respect to most detrital grains, and extensively replaced feldspars. Nodular concretions and sporadic, irregular crystals of ferroan calcite are inferred to be the remnants of this intergranular cement. The distribution of porosity zones in the Tartan downthrown block is related to the present structure and oil-water contact, supporting the interpretation of a secondary origin for much of the present porosity. Highly compacted sandstones interbedded with the porous sandstones result from a combination of early compaction, brittle framework collapse following the generation of secondary porosity and late grain-to-grain contact dissolution. Aggressive fluids responsible for the generation of the cement dissolution porosity are inferred to have been expelled from the Kimmeridge Clay in the adjacent Witch Ground Graben. The preservation of secondary porosity in Piper Formation sandstones is due to the relative timing of secondary porosity generation and subsequent hydrocarbon migration.

Siliciclastic Diagenesis in Paleocene-Eocene Reservoir Sandstones of the Taranaki Basin, New Zealand

1988 ◽  
Vol 6 (2) ◽  
pp. 151-169 ◽  
Author(s):  
G.J. van der Lingen ◽  
G.A. Challis ◽  
P.H. Robinson ◽  
D. Smale ◽  
W.A. Walters
Keyword(s):  
Compaction Pressure ◽  
Source Rocks ◽  
Heavy Minerals ◽  
Reservoir Quality ◽  
Depth Range ◽  
Secondary Porosity ◽  
Carbonate Cement ◽  
Continental Block ◽  
Reservoir Sandstones ◽  
Porosity Development

Present-day producing hydrocarbon reservoirs in the Taranaki Basin occur in the Paleocene-Eocene Kapuni Group, both onshore and offshore. The Kapuni Group has been encountered only in drillholes, the top being at depths ranging from 2 to 4 km. It consists of fluvial, paralic, near-shore and shelf sediments, containing proven and prospective reservoir sandstones with variable grain-size, sorting, porosity and permeability. Compositionally, the sandstones are sub-feldsarenites to feldsarenites, derived from continental block source rocks. Diagenetic features adversely affecting reservoir quality are compaction, pressure solution, clay neoformation, quartz overgrowth and neoformation, and carbonate neoformation. Secondary porosity development enhances reservoir quality, through dissolution of earlier (corroding) carbonate cement, dissolution of calcic plagioclase. quartz dissolution, and grain fracturing. Intrastratal solution of heavy minerals suggests that the Kapuni Group sedimentary sequence had progressed into the thermobaric hydrogeological regime. Kaolinite is an early diagenetic clay mineral, while illite and chlorite are formed later (> 3 km). Quartz overgrowth has only been observed in samples from deeper than 3 km. Carbonate cemented horizons, although of relatively limited occurrence, have been observed over the entire studied depth range. Good secondary porosity development, due to (probable) carobate-cement dissolution has been observed in the gas/condensate reservoir of the Maui Field, and in the Witiora Sandstone (base Kapuni Group) in Tane-1, indicating that potential reservoirs can exist at depths of at least 3.5 km.

scholarly journals Integrated Porosity Classification and Quantification Scheme for Enhanced Carbonate Reservoir Quality: Implications from the Miocene Malaysian Carbonates

2021 ◽  
Vol 9 (12) ◽  
pp. 1410
Author(s):  
Hammad Tariq Janjuhah ◽  
George Kontakiotis ◽  
Abdul Wahid ◽  
Dost Muhammad Khan ◽  
Stergios D. Zarkogiannis ◽  
...  
Keyword(s):  
Total Porosity ◽  
Depositional Environments ◽  
Carbonate Reservoir ◽  
Pore System ◽  
Secondary Porosity ◽  
Rock Classification ◽  
Thin Sections ◽  
Diagenetic Processes ◽  
Wide Range ◽  
Pore Types

The pore system in carbonates is complicated because of the associated biological and chemical activity. Secondary porosity, on the other hand, is the result of chemical reactions that occur during diagenetic processes. A thorough understanding of the carbonate pore system is essential to hydrocarbon prospecting. Porosity classification schemes are currently limited to accurately forecast the petrophysical parameters of different reservoirs with various origins and depositional environments. Although rock classification offers a way to describe lithofacies, it has no impact on the application of the poro-perm correlation. An outstanding example of pore complexity (both in terms of type and origin) may be found in the Central Luconia carbonate system (Malaysia), which has been altered by diagenetic processes. Using transmitted light microscopy, 32 high-resolution pictures were collected of each thin segment for quantitative examination. An FESEM picture and a petrographic study of thin sections were used to quantify the grains, matrix, cement, and macroporosity (pore types). Microporosity was determined by subtracting macroporosity from total porosity using a point-counting technique. Moldic porosity (macroporosity) was shown to be the predominant type of porosity in thin sections, whereas microporosity seems to account for 40 to 50% of the overall porosity. Carbonates from the Miocene have been shown to possess a substantial quantity of microporosity, making hydrocarbon estimate and production much more difficult. It might lead to a higher level of uncertainty in the estimation of hydrocarbon reserves if ignored. Existing porosity classifications cannot be used to better understand the poro-perm correlation because of the wide range of geological characteristics. However, by considering pore types and pore structures, which may be separated into macro- and microporosity, the classification can be enhanced. Microporosity identification and classification investigations have become a key problem in limestone reservoirs across the globe.

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