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 Carbonate reservoir rock typing algorithm based on integrated approach (IRT)

2021 ◽  
Vol 6 (4) ◽  
pp. 62-70
Author(s):  
Mariia A. Kuntsevich ◽  
Sergey V. Kuznetsov ◽  
Igor V. Perevozkin
Keyword(s):  
Water Saturation ◽  
Integrated Approach ◽  
Learning Technologies ◽  
Carbonate Reservoir ◽  
Reservoir Rock ◽  
Static Properties ◽  
Reservoir Properties ◽  
Optimal Method ◽  
Rock Types ◽  
Rock Typing

The goal of carbonate rock typing is a realistic distribution of well data in a 3D model and the distribution of the corresponding rock types, on which the volume of hydrocarbon reserves and the dynamic characteristics of the flow will depend. Common rock typing approaches for carbonate rocks are based on texture, pore classification, electrofacies, or flow unit localization (FZI) and are often misleading because they based on sedimentation processes or mathematical justification. As a result, the identified rock types may poorly reflect the real distribution of reservoir rock characteristics. Materials and methods. The approach described in the work allows to eliminate such effects by identifying integrated rock types that control the static properties and dynamic behavior of the reservoir, while optimally linking with geological characteristics (diagenetic transformations, sedimentation features, as well as their union effect) and petrophysical characteristics (reservoir properties, relationship between the porosity and permeability, water saturation, radius of pore channels and others). The integrated algorithm consists of 8 steps, allowing the output to obtain rock-types in the maximum possible way connecting together all the characteristics of the rock, available initial information. The first test in the Middle East field confirmed the applicability of this technique. Results. The result of the work was the creation of a software product (certificate of state registration of the computer program “Lucia”, registration number 2021612075 dated 02/11/2021), which allows automating the process of identifying rock types in order to quickly select the most optimal method, as well as the possibility of their integration. As part of the product, machine learning technologies were introduced to predict rock types based on well logs in intervals not covered by coring studies, as well as in wells in which there is no coring.

scholarly journals Reservoir Properties of Low-Permeable Carbonate Rocks: Experimental Features

Energies ◽  
2020 ◽  
Vol 13 (9) ◽  
pp. 2233 ◽  
Author(s):  
Aliya Mukhametdinova ◽  
Andrey Kazak ◽  
Tagir Karamov ◽  
Natalia Bogdanovich ◽  
Maksim Serkin ◽  
...  
Keyword(s):  
Gas Permeability ◽  
Total Porosity ◽  
Carbonate Reservoir ◽  
Reservoir Rock ◽  
Crushed Rock ◽  
Void Space ◽  
Reservoir Properties ◽  
Rock Samples ◽  
Liquid Saturation ◽  
Imaging Results

This paper presents an integrated petrophysical characterization of a representative set of complex carbonate reservoir rock samples with a porosity of less than 3% and permeability of less than 1 mD. Laboratory methods used in this study included both bulk measurements and multiscale void space characterization. Bulk techniques included gas volumetric nuclear magnetic resonance (NMR), liquid saturation (LS), porosity, pressure-pulse decay (PDP), and pseudo-steady-state permeability (PSS). Imaging consisted of thin-section petrography, computed X-ray macro- and microtomography, and scanning electron microscopy (SEM). Mercury injection capillary pressure (MICP) porosimetry was a proxy technique between bulk measurements and imaging. The target set of rock samples included whole cores, core plugs, mini cores, rock chips, and crushed rock. The research yielded several findings for the target rock samples. NMR was the most appropriate technique for total porosity determination. MICP porosity matched both NMR and imaging results and highlighted the different effects of solvent extraction on throat size distribution. PDP core-plug gas permeability measurements were consistent but overestimated in comparison to PSS results, with the difference reaching two orders of magnitude. SEM proved to be the only feasible method for void-scale imaging with a spatial resolution up to 5 nm. The results confirmed the presence of natural voids of two major types. The first type was organic matter (OM)-hosted pores, with dimensions of less than 500 nm. The second type was sporadic voids in the mineral matrix (biogenic clasts), rarely larger than 250 nm. Comparisons between whole-core and core-plug reservoir properties showed substantial differences in both porosity (by a factor of 2) and permeability (up to 4 orders of magnitude) caused by spatial heterogeneity and scaling.

A new workflow to improve the carbonate reservoir types discrimination combing the empirical model decomposition and energy entropy classification methods

2018 ◽  
Vol 6 (3) ◽  
pp. T555-T567
Author(s):  
Zhuoying Fan ◽  
Jiagen Hou ◽  
Chengyan Lin ◽  
Xinmin Ge
Keyword(s):  
Rock Type ◽  
Well Logging ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Reservoir Rock ◽  
Well Logs ◽  
Well Log ◽  
Tahe Oilfield ◽  
Rock Types ◽  
Reservoir Type

Classification and well-logging evaluation of carbonate reservoir rock is very difficult. On one side, there are many reservoir pore spaces developed in carbonate reservoirs, including large karst caves, dissolved pores, fractures, intergranular dissolved pores, intragranular dissolved pores, and micropores. On the other side, conventional well-logging response characteristics of the various pore systems can be similar, making it difficult to identify the type of pore systems. We have developed a new reservoir rock-type characterization workflow. First, outcrop observations, cores, well logs, and multiscale data were used to clarify the carbonate reservoir types in the Ordovician carbonates of the Tahe Oilfield. Three reservoir rock types were divided based on outcrop, core observation, and thin section analysis. Microscopic and macroscopic characteristics of various rock types and their corresponding well-log responses were evaluated. Second, conventional well-log data were decomposed into multiple band sets of intrinsic mode functions using empirical mode decomposition method. The energy entropy of each log curve was then investigated. Based on the decomposition results, the characteristics of each reservoir type were summarized. Finally, by using the Fisher discriminant, the rock types of the carbonate reservoirs could be identified reliably. Comparing with conventional rock type identification methods based on conventional well-log responses only, the new workflow proposed in this paper can effectively cluster data within each rock types and increase the accuracy of reservoir type-based hydrocarbon production prediction. The workflow was applied to 213 reservoir intervals from 146 wells in the Tahe Oilfield. The results can improve the accuracy of oil-production interval prediction using well logs over conventional methods.

Enhanced and Rock Typing-Based Reservoir Characterization of the Palaeocene Harash Carbonate Reservoir-Zelten Field-Sirte Basin-Libya

2021 ◽  
Author(s):  
Mohamed Masoud ◽  
W. Scott Meddaugh ◽  
Masoud Eljaroshi ◽  
Khaled Elghanduri
Keyword(s):  
Rock Type ◽  
Carbonate Reservoir ◽  
Classification Model ◽  
Reservoir Rocks ◽  
The Core ◽  
Core Samples ◽  
Rock Types ◽  
Rock Typing ◽  
Open Hole ◽  
Type Classification

Abstract The Harash Formation was previously known as the Ruaga A and is considered to be one of the most productive reservoirs in the Zelten field in terms of reservoir quality, areal extent, and hydrocarbon quantity. To date, nearly 70 wells were drilled targeting the Harash reservoir. A few wells initially naturally produced but most had to be stimulated which reflected the field drilling and development plan. The Harash reservoir rock typing identification was essential in understanding the reservoir geology implementation of reservoir development drilling program, the construction of representative reservoir models, hydrocarbons volumetric calculations, and historical pressure-production matching in the flow modelling processes. The objectives of this study are to predict the permeability at un-cored wells and unsampled locations, to classify the reservoir rocks into main rock typing, and to build robust reservoir properties models in which static petrophysical properties and fluid properties are assigned for identified rock type and assessed the existed vertical and lateral heterogeneity within the Palaeocene Harash carbonate reservoir. Initially, an objective-based workflow was developed by generating a training dataset from open hole logs and core samples which were conventionally and specially analyzed of six wells. The developed dataset was used to predict permeability at cored wells through a K-mod model that applies Neural Network Analysis (NNA) and Declustring (DC) algorithms to generate representative permeability and electro-facies. Equal statistical weights were given to log responses without analytical supervision taking into account the significant log response variations. The core data was grouped on petrophysical basis to compute pore throat size aiming at deriving and enlarging the interpretation process from the core to log domain using Indexation and Probabilities of Self-Organized Maps (IPSOM) classification model to develop a reliable representation of rock type classification at the well scale. Permeability and rock typing derived from the open-hole logs and core samples analysis are the main K-mod and IPSOM classification model outputs. The results were propagated to more than 70 un-cored wells. Rock typing techniques were also conducted to classify the Harash reservoir rocks in a consistent manner. Depositional rock typing using a stratigraphic modified Lorenz plot and electro-facies suggest three different rock types that are probably linked to three flow zones. The defined rock types are dominated by specifc reservoir parameters. Electro-facies enables subdivision of the formation into petrophysical groups in which properties were assigned to and were characterized by dynamic behavior and the rock-fluid interaction. Capillary pressure and relative permeability data proved the complexity in rock capillarity. Subsequently, Swc is really rock typing dependent. The use of a consistent representative petrophysical rock type classification led to a significant improvement of geological and flow models.

scholarly journals Fluid Saturation Predictions in a “Transition Zone” Carbonate Reservoir, Abu Dhabi

GeoArabia ◽  
1996 ◽  
Vol 1 (4) ◽  
pp. 551-566
Author(s):  
Anthony Kirkham ◽  
Mohamed Bin Juma ◽  
Tilden A.M. McKean ◽  
Anthony F. Palmer ◽  
Michael J. Smith ◽  
...  
Keyword(s):  
Transition Zone ◽  
Free Water ◽  
Analysis Data ◽  
Carbonate Reservoir ◽  
Rock Types ◽  
Fluid Saturation ◽  
Porosity And Permeability ◽  
Capillary Pressures ◽  
Seismic Amplitudes ◽  
Low Amplitude

ABSTRACT The field is a low amplitude structure with a chalky, Lower Cretaceous, Thamama reservoir characterised by a large hydrocarbon transition zone. Porosity generally decreases with depth within the trap although porosity versus depth trends are skewed by tilting. Porosity and permeability mapping was therefore achieved using templates based on seismic amplitudes. Special core analysis data were used to construct algorithms of Leverett J functions versus saturation for a variety of rock types mapped throughout the 3-D geological model of the field. The templated poroperms were then combined with capillary pressures to predict fluid saturations from these algorithms. The modelling of fluid distributions was therefore dependent upon heterogeneities imposed by the rock fabrics. Calibrating the model-predicted saturations against log-derived saturations at the wells involved regression techniques which were complicated by: notional structural tilting of the free water level, imbibition, hysteresis and permeability averaging procedures. Filtered “stick displays” proved useful in assessing the quality of the calibrations and were invaluable tools for highlighting and investigating data anomalies.

scholarly journals Groundwater Chemistry of Some Selected Areas in Southeastern Norway

1980 ◽  
Vol 11 (1) ◽  
pp. 33-54 ◽  
Author(s):  
Jens-Olaf Englund ◽  
Jan Aug Myhrstad
Keyword(s):  
Land Surface ◽  
Mineral Water ◽  
Sea Water ◽  
Electrical Conductance ◽  
Reservoir Rock ◽  
Rock Fractures ◽  
Sea Salts ◽  
Reservoir Rocks ◽  
Rock Types ◽  
Groundwater Samples

Within three areas in Southeastern Norway, Lake Mjøsa district, Ås and Moss - Jeløy, groundwater samples for chemical analysis were collected during the years 1971–77 from 98 drilled wells in bedrocks. The water was taken at depths ranging from 15 m to 110 m below the land surface. The groundwater surface is usually present well below the overlying unconsolidated deposits of glacial, glacifluvial or marine origin. The movement of groundwater within the aquifers investigated is so slow that regional changes in water quality is not only dependent on weathering in the unsaturated zone, but also dependent on the solution of reservoir rocks below the groundwater surface. Variations in specific electrical conductance (20°C) largely reflects the different reservoir rock types. The highest values, around 550 μS/cm, are typically found in dark calcareous shales, while sandstones and gneisses give values around 300 μS/cm. The areas Ås and Moss-Jeløy are situated below the Late-Postglacial marine limit. The groundwater is here more or less influenced by ancient sea salts, perhaps also by fossil sea water, left over in sediments or in rock fractures. Brackish groundwater was also found. The composition of groundwater is largely governed by mineral-water equilibria. Most investigated water samples have not reached equilibrium with their surrounding minerals.

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 Integrated rock typing and pore facies analyses in a heterogeneous carbonate for saturation height modelling, a case study from Fahliyan Formation, the Persian Gulf

2021 ◽  
Vol 11 (4) ◽  
pp. 1577-1595
Author(s):  
Rasoul Ranjbar-Karami ◽  
Parisa Tavoosi Iraj ◽  
Hamzeh Mehrabi
Keyword(s):  
Capillary Pressure ◽  
Water Saturation ◽  
High Energy ◽  
Carbonate Reservoir ◽  
Reservoir Rock ◽  
Initial Water ◽  
Rock Types ◽  
Rock Typing ◽  
Pore Types ◽  
Fitting Parameters

AbstractKnowledge of initial fluids saturation has great importance in hydrocarbon reservoir analysis and modelling. Distribution of initial water saturation (Swi) in 3D models dictates the original oil in place (STOIIP), which consequently influences reserve estimation and dynamic modelling. Calculation of initial water saturation in heterogeneous carbonate reservoirs always is a challenging task, because these reservoirs have complex depositional and diagenetic history with a complex pore network. This paper aims to model the initial water saturation in a pore facies framework, in a heterogeneous carbonate reservoir. Petrographic studies were accomplished to define depositional facies, diagenetic features and pore types. Accordingly, isolated pores are dominant in the upper parts, while the lower intervals contain more interconnected interparticle pore types. Generally, in the upper and middle parts of the reservoir, diagenetic alterations such as cementation and compaction decreased the primary reservoir potential. However, in the lower interval, which mainly includes high-energy shoal facies, high reservoir quality was formed by primary interparticle pores and secondary dissolution moulds and vugs. Using huge number of primary drainage mercury injection capillary pressure tests, we evaluate the ability of FZI, r35Winland, r35Pittman, FZI* and Lucia’s petrophysical classes in definition of rock types. Results show that recently introduced rock typing method is an efficient way to classify samples into petrophysical rock types with same pore characteristics. Moreover, as in this study MICP data were available from every one meter of reservoir interval, results show that using FZI* method much more representative sample can be selected for SCAL laboratory tests, in case of limitation in number of SCAL tests samples. Integration of petrographic analyses with routine (RCAL) and special (SCAL) core data resulted in recognition of four pore facies in the studied reservoir. Finally, in order to model initial water saturation, capillary pressure data were averaged in each pore facies which was defined by FZI* method and using a nonlinear curve fitting approach, fitting parameters (M and C) were extracted. Finally, relationship between fitting parameters and porosity in core samples was used to model initial water saturation in wells and between wells. As permeability prediction and reservoir rock typing are challenging tasks, findings of this study help to model initial water saturation using log-derived porosity.

scholarly journals PETROGRAPHIC CHARACTERISTICS OF THE RESERVOIR ROCKS IN THE BAT-UPPER JURASSIC DEPOSITS OF THE SOUTH OF WESTERN-SIBERIAN PETROLEUM BASIN

2019 ◽  
Vol 2 (1) ◽  
pp. 25-31
Author(s):  
Lyudmila Vakulenko ◽  
Aleksey Popov ◽  
Sergey Rodyakin ◽  
Evgeniy Khabarov ◽  
Peter Yan
Keyword(s):  
Oil And Gas ◽  
Upper Jurassic ◽  
The South ◽  
Reservoir Properties ◽  
Petrographic Composition ◽  
Reservoir Rocks ◽  
Regional Sources ◽  
Porosity And Permeability ◽  
Maximum Parameters ◽  
Petroleum Basin

The features of the petrographic composition of the bath-upper Jurassic silt-sand rocks exposed by wells in the South of the West Siberian oil and gas basin are considered. The study is focused on the parameters that had a significant influence on the reservoir properties of rocks: granulometric and mineral-petrographic composition of the clastic part of rocks, cement content, structure and composition. Some conclusions are drawn on the spatial distribution of rocks of different composition within the subisochronous sedimentary complexes. It is assumed that significant variations in their composition are caused by a complex combination of varying degrees of interdependent factors: influence of local and regional sources of clastic material, peculiarities of redistribution of material during its transportation and sedimentation, and post-sedimentation changes. Most variable values of reservoir properties, with a recorded maximum parameters of porosity and permeability are obtained for the rocks of Medium-Upper Oxford complex on Verkhnetarskaya, Dedovskaya, Basinskaya, Veselovskaya, to a lesser extent, Kasmanskaya, Vostochnaya and Tai-Dasskaya drilling sites.

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