scholarly journals Generation of authigenic clay minerals during diagenesis and their influences on porosity and permeability of Oligocene sandstone reservoir rocks, from a well in the west of Cuu Long basin

2014 ◽  
Vol 17 (3) ◽  
pp. 21-26
Author(s):  
Toan Minh Ho ◽  
Phuong Kim Lieu ◽  
Thuy Thi Doan ◽  
Phuong Thi Ngoc Bui
Keyword(s):  
Clay Minerals ◽  
Fluid Flows ◽  
Reservoir Rock ◽  
Burial Depth ◽  
High Porosity ◽  
Pore Waters ◽  
The West ◽  
Reservoir Rocks ◽  
Porosity And Permeability ◽  
Sandstone Reservoir

Porosity and permeability play a prerequisite role for hydrocarbon reservoirs and fluid flows, especially in sandstone reservoir rocks. The rocks with high porosity decrease down to lower porosity with increasing burial depth due to compaction, cementation and precipitation of authigenic minerals in pores from over saturated solution of minerals. The detailed study of the authigenic clay mineral formation in pore spaces of sandstone reservoir rocks is therefore crucial to estimate the degree of reservoir rock quality. In this study 20 sandstone cores taken from the interval burial depths of 3,700 m - 4,200 m from Oligocene sandstone sequence of a well in the West of the Cuu Long basin, offshore Vietnam, were analyzed by SEM and thin section. Authigenic clay minerals were formed due to temperature and chemistry changes and owing to dissolution of less stable minerals in these burial depths. Authigenic chlorite mineral appears quite abundantly and illite is less frequently. Chlorite was formed from the elements Al and Si, which were released from dissolved grains and Fe and Mg supplied from breakdown of the ferromagnesian minerals of rock fragments and matrix components into pore waters in the burial stage. Illite is associated with the expense of grain dissolution of feldspar, volcanic fragment. Chlorite mostly appears as a coating or mats comprising of small pseudo-hexagonal crystals arranged perpendicular to detrital grain surfaces. Grainrimming chlorites on quartz grain are responsible for the preservation of the porosity in the sandstones because they limit the formation of quartz overgrowth. Additionally fibrous or flaky illite bridging the pores between the grains creates permeability barriers to fluid flows through the sandstones. Thus illite significantly reduces the permeability but to lesser extent affect porosity. Locally, smectite mixes with illite or chlorite and is not abundant in the studied samples. It therefore has no significant impact on the porosity and permeability as well. The variations of the porosity and the permeability of the studied sandstones depend on the generated degree and the arranged patterns of chlorite and illite in pore spaces.

scholarly journals Petrographical characteristics and post-depositional alteration affecting porosity and permeability of Oligocene sandstones, block 15-1/05, Cuu Long basin

2020 ◽  
Vol 4 (2) ◽  
pp. First
Author(s):  
Thanh Ngoc Do ◽  
Duyen Thi Pham ◽  
Phuong Kim Lieu
Keyword(s):  
Clay Minerals ◽  
Oil And Gas ◽  
Gas Storage ◽  
Early Diagenesis ◽  
Burial Depth ◽  
Reservoir Rocks ◽  
Potential Reservoir ◽  
Negative Effect ◽  
Porosity And Permeability ◽  
Grain Sorting

Petrographical characteristics and post-depositional alteration studies of sandstones are the two important factors to reservoir rocks, which affect oil and gas storage and permeability of reservoir rocks. This study revealed petrographical characteristics, post-depositional alteration, and their influence on the porosity and permeability of Oligocene sandstones, including C, D, and E and F sequences, block 15-1/05, Cuu Long Basin. The results show that most of the sandstones were arkose, lithic arkose, and sporadically interbedded by feldspathic greywacke. The post-depositional alteration was progressively increasing following the burial depth from early diagenesis of sequence C, to intermediate diagenesis of sequence D and advanced diagenesis of sequence E and F. The post-depositional alterations significantly influenced on the porosity of the Oligocene sandstone were the cementation and mechanical compaction. They reduced the porosity and permeability of the sandstone. Additionally, authigenic clay minerals have a negative effect on permeability in which sandstones were rich illite and illite-smectite clay minerals, and the permeability tended to decrease stronger than others. Our results showed that the potential reservoir rocks of Oligocene sandstones, block 15-1/05 were sequence E and F sandstones that are in well grain sorting, well grain roundness shape, and contained a small number of cement, particularly the absence of illite and illite-smectite.

THE BASIC TYPES OF SECONDARY CHANGES IN RESERVOIR ROCKS IN THE TERRITORY OF THE WEST SIBERIA PLATE

2015 ◽  
pp. 26-30
Author(s):  
A. V. Podnebesnykh ◽  
S. V. Kuznetsov ◽  
V. P. Ovchinnikov
Keyword(s):  
Oil Recovery ◽  
West Siberia ◽  
Recovery Factor ◽  
Change Processes ◽  
The West ◽  
Reservoir Rocks ◽  
Tectonically Active ◽  
Porosity And Permeability ◽  
Active Zones ◽  
Regional Character

On the example of the group of fields in the West Siberia North the basic types of secondary changes in reservoir rocks are reviewed. Some of the most common types of such changes in the West Siberian plate territory include the processes of zeolitization, carbonation and leaching. These processes have, as a rule, a regional character of distribution and are confined to the tectonically active zones of the earth's crust. Due to formation of different mineral paragenesises the secondary processes differently affect the reservoir rocks porosity and permeability: thus, zeolitization and carbonization promote to reducing the porosity and permeability and leaching improvement. All this, ultimately leads to a change of the oil recovery factor and hydrocarbons production levels. Study and taking into account of the reservoir rocks secondary change processes can considerably influence on placement of operating well stock and on planning of geological and technological actions.

Reservoir Physical Property and Controlling Factors for the Lower Youshashan Formation in Youshashan-Dawusi Area, Southwestern Qaidam Basin

2014 ◽  
Vol 675-677 ◽  
pp. 1363-1367 ◽  
Author(s):  
Guo Min Chen ◽  
Quan Wen Liu ◽  
Min Quan Xia ◽  
Xiang Sheng Bao
Keyword(s):  
Qaidam Basin ◽  
Sedimentary Environment ◽  
Physical Property ◽  
Controlling Factors ◽  
Reservoir Rock ◽  
High Porosity ◽  
Delta Front ◽  
Thin Sections ◽  
Rock Types ◽  
Porosity And Permeability

The core data, casting thin sections and scanning electron microscopy are used to study the clastic reservoir characteristics and controlling factors of reservoir growth. It indicated that the main reservoir rock types are lithic arkose, Feld spathic sandstone, and a small amount of feldspar lithic sandstone, and with compositional maturity and low to middle structural maturity. Moreover, the primary reservoir space types are mainly intergranular pores, secondary are secondary pores, and reservoir types belong to the medium-high porosity and permeability, and the average porosity and permeability of lower Youshashan formation are 17.70% and 112.5×10-3μm2 separately. Furthermore, the reservoir body is mainly sand body result from deposits of distributary channel and mouth bar of which belong to the braided delta front, and the planar physical property tends to be better reservoir to worse reservoir from northwest to southeast. Finally, mainly factors to control the distribution of reservoir physical property, are the sedimentary environment and lithology, were worked out.

scholarly journals Coupled experimental/numerical workflow for assessing quantitative diagenesis and dynamic porosity/permeability evolution in calcite-cemented sandstone reservoir rocks

2018 ◽  
Vol 73 ◽  
pp. 36 ◽  
Author(s):  
Steven Claes ◽  
Fadi H. Nader ◽  
Souhail Youssef
Keyword(s):  
Permeability Evolution ◽  
Flow Properties ◽  
New Approach ◽  
Reservoir Rocks ◽  
Pore Blocking ◽  
Diagenetic Processes ◽  
Porosity And Permeability ◽  
Sandstone Reservoir ◽  
Calcite Cement ◽  
Host Rocks

Some of the world best hydrocarbon reservoirs (carbonates and siliciclastics) are also believed to be valuable for subsurface storage of CO2 and other fluids. Yet, these reservoirs are heterogeneous in terms of their mineralogy and flow properties, at varying spatial-temporal scales. Therefore, predicting the porosity and permeability (flow properties) evolution of carbonates and sandstones remains a tedious task. Diagenesis refers to the alteration of sedimentary rocks through geologic time, mainly due to rock-fluid interactions. It affects primarily the flow properties (porosity and permeability) of already heterogeneous reservoir rocks. In this project a new approach is proposed to calculate/quantify the influence of diagenetic phases (e.g. dissolution, cement plugging) on flow properties of typical sandstone reservoir rocks (Early Jurassic Luxembourg Formation). A series of laboratory experiments are performed in which diagenetic phases (e.g. pore blocking calcite cement in sandstone) are selectively leached from pre-studied samples, with the quantification of the petrophysical characteristics with and without cement to especially infer permeability evolution. Poorly and heavily calcite-cemented sandstone samples, as well as some intermediate cemented samples were used. The results show a distinctive dissolution pattern for different cementation grades and varying Representative Elementary Volumes (REVs). These conclusions have important consequences for upscaling diagenesis effects on reservoirs, and the interpretation of geochemical modelling results of diagenetic processes. The same approach can be applied on other type of cements and host-rocks, and could be improved by integrating other petrophysical analyses (e.g. petroacoustic, NMR).

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 Liquid and Gas Corrected Permeability Correlation for Heterogeneous Carbonate Reservoir Rocks

2020 ◽  
pp. 36-50
Author(s):  
Sadonya Jamal Mustafa ◽  
Fraidoon Rashid ◽  
Khalid Mahmmud Ismail
Keyword(s):  
Gas Permeability ◽  
Carbonate Reservoir ◽  
Reservoir Rock ◽  
Reservoir Properties ◽  
Reservoir Rocks ◽  
Rock Types ◽  
Liquid Permeability ◽  
Porosity And Permeability ◽  
Permeability Distribution ◽  
Reservoir Type

Permeability is considered as an efficient parameter for reservoir modelling and simulation in different types of rocks. The performance of a dynamic model for estimation of reservoir properties based on liquid permeability has been widely established for reservoir rocks. Consequently, the validated module can be applied into another reservoir type with examination of the validity and applicability of the outcomes. In this study the heterogeneous carbonate reservoir rock samples of the Tertiary Baba Formation have been collected to create a new module for estimation of the brine permeability from the corrected gas permeability. In addition, three previously published equations of different reservoir rock types were evaluated using the heterogenous carbonate samples. The porosity and permeability relationships, permeability distribution, pore system and rock microstructures are the dominant factors that influenced on the limitation of these modules for calculating absolute liquid permeability from the klinkenberg-corrected permeability. The most accurate equation throughout the selected samples in this study was the heterogenous module and the lowest quality permeability estimation was derived from the sandstone module.

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

Geosciences ◽  
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.

scholarly journals Hydraulic flow unit classification from core data: case study of the Z gas reservoir, Poland

2021 ◽  
Vol 62 (3) ◽  
pp. 29-36
Author(s):  
Keyword(s):  
Flow Unit ◽  
Reservoir Rock ◽  
Hydrocarbon Production ◽  
Reservoir Rocks ◽  
Hydraulic Flow ◽  
Flow Units ◽  
Porosity And Permeability ◽  
Homogeneous Section ◽  
Hydraulic Flow Units

Permeability and porosity are essential parameters for estimating hydrocarbon production from reservoir rocks. They are combined in an additional factor, the Flow Zone Index (FZI), which is the basis for defining the hydraulic flow unit (HFU). Each HFU is a homogeneous section of a reservoir rock with stable parameters that allow for media flow. Hydraulic flow units are determined from the porosity and permeability of core or well logs. The simple statistical methods are applied for HFU classification and then improve permeability prediction. This paper also shows how to quickly apply the global hydraulic elements (GHE) method for HFU classification. The methodology is tested on the Miocene formation of a deltaic facies from the Carpathian Foredeep in South-Eastern Poland.

Adsorption Of Nonionic Surfactants On Clay Minerals

2012 ◽  
Author(s):  
Radzuan Junin ◽  
Tahmineh Amirian ◽  
Ahmad Kamal Idris
Keyword(s):  
Clay Minerals ◽  
Clay Mineral ◽  
Oil Recovery ◽  
Nonionic Surfactants ◽  
Mineralogical Composition ◽  
Reservoir Rock ◽  
Chemical Solution ◽  
Reservoir Rocks ◽  
Oil Water ◽  
Rock Minerals

The adsorption of surfactants from aqueous solutions in porous media is very significant in the enhanced oil recovery (EOR) of oil reservoirs. Surfactant loss due to adsorption on the reservoir rocks weakens the efficiency of the chemical solution injected to decrease the oil–water interfacial tension (IFT). This study investigated the effect of the mineralogical composition of adsorbents on adsorption. Nonionic surfactants were injected into sand packs in which different amounts of clay minerals (kaolinite and illite) were added and compacted in a sand pack holder. The amount of surfactant adsorbed was quantified by subtracting the concentration of surfactants after adsorption from the initial concentration. It was concluded that there is a relationship between the adsorption of nonionic surfactants and the amount of clay mineral in the adsorbents because the quantity of surfactant adsorbed by adsorbents increased when the percentage of clay mineral in the adsorbents increased (from 2 to 8% in the sand packs). The clay mineral illite has a stronger adsorption power for nonionic surfactants than does kaolinite. Key words: Adsorption, reservoir rock minerals, clay minerals, nonionic surfactants

Carbonate Pore System Characterization, a Study Case from Drowning Cap Sequence in VITA Field, ExxonMobil Block Cepu Limited (EMCL)

2021 ◽  
Author(s):  
V.T Dewi
Keyword(s):  
Reservoir Simulation ◽  
Carbonate Reservoir ◽  
Reservoir Rock ◽  
Reservoir Quality ◽  
High Porosity ◽  
Pore System ◽  
Diagenetic Processes ◽  
Porosity And Permeability ◽  
Study Case ◽  
Low Porosity

Carbonate rocks are known as one of the principal reservoir rocks in the world due to their good porosity and permeability. However, the heterogeneity of carbonate reservoir quality is difficult to predict. Variability of diagenetic processes overprinting carbonate depositional texture has resulted in a complex carbonate pore system. As a consequence, this complexity results in a harder reservoir characterization and also a discrepancy between actual and model properties, that leads to a harder history match in reservoir simulation. By presenting a study case from the Drowning Cap Sequence in the VITA Reservoir Block Cepu, this paper will present a comprehensive approach which focusing on characterization of a carbonate pore system for optimum geomodel, simulation and surveillance. This approach utilized static data of 100 ft total of cores, ±500 thin sections, well, and image logs. The study has resulted in definition of four Carbonate Reservoir Rock Types (RRT) which were clustered using the analysis of carbonate dominant pore types and the porosity-permeability relationship. Results revealed that there are 4 RRTs observed as follows: (1) RRT 1 – Touching Vugs-dominated, with high porosity and permeability, (2) RRT 2 – Interparticle- and Moldic-dominated, with moderate to high porosity value and lower permeability than RRT 1, (3) RRT 3 – Microfracture-dominated, with very low porosity value and low to moderate permeability, and (4) RRT 4 – Minimum Dissolution, with very low porosity and permeability value, lower than RRT 3. Each RRT was integrated with well and image logs to understand its characteristics and behavior. Ultimately, all data were integrated, analyzed and successfully captured carbonate reservoir quality variation, distribution and depositional evolution along with overprinted diagenetic processes vertically and laterally. This approach successfully captured carbonate heterogeneity which ultimately will be useful to develop better geological and reservoir simulation models after being integrated with dynamic data and observations.

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