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.

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.

Oil Saturation Index in Hydrophobic Carbonate Reservoir: Evaluation Aspects

2021 ◽  
Author(s):  
Regina Khanbikova ◽  
Venera Bazarevskaya ◽  
Oleg Sotnikov ◽  
Albert Bachkov
Keyword(s):  
Carbonate Rocks ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Reservoir Rock ◽  
Western Slope ◽  
Void Space ◽  
The South ◽  
Reservoir Properties ◽  
Lower Carboniferous ◽  
Hydrocarbon Reserves

Abstract Hydrocarbon reserves in carbonate reservoirs account for 38% - 60% of total world reserves, according to different estimates. In Tatarstan, carbonate reservoirs are found, mostly, in the eastern slope of the Melekess Depression and the South-Tatarian Arch. The carbonate reservoirs are confined to the Middle and Lower Carboniferous sediments, the Upper Devonian (including the domanik sediments), and the Upper Permian (the Kazanian heavy oil accumulations). Considering an extensive geographic and stratigraphic range and differing tectonic and sedimentation environments, the carbonate rocks are characterized by a variety of reservoir properties. In contrast to terrigenous rocks, the carbonate void space is complicated by secondary processes that took place much later than the sedimentogenesis-lithogenesis stage. Numerous fissures, caves, sutures, and stylolites form the void space of the reservoir rock matrix containing commercial hydrocarbon reserves. In addition to fracturing and vugginess contributing to increase of void space of carbonate rocks, the secondary processes include sulphatisation and secondary dolomitization (in limestones), adding to deterioration of reservoir properties. The secondary processes impede understanding and evaluation of reservoir properties and saturation potential, in particular, determination of the oil and gas saturation factors (Dyakonova T.F. et al, 2019, Akhmetov R.T. et al, 2017)/ In the western slope of the South-Tatarian Arch, carbonate reservoirs are confined to the Middle and Lower Carboniferous sediments. Numerous RCAL and SCAL investigations provided valuable insight into these targets. In this paper, we used data from the laboratory experiments and studies of core and oil samples from the six neighbor fields on the western slope of the South-Tatarian Arch. Because of common sedimentological and tectonic sedimentation environments and lithological similarity of rocks within the stratigraphic referencing, the six fields under analysis were considered as analogous, and the results of the laboratory studies of the samples were reviewed collectively.

A Liquid-Freon Permeameter

1962 ◽  
Vol 2 (01) ◽  
pp. 18-20
Author(s):  
B.G. Hurd
Keyword(s):  
Gas Permeability ◽  
Reservoir Rock ◽  
Explosion Hazard ◽  
Petroleum Reservoir ◽  
Laboratory Equipment ◽  
Reservoir Rocks ◽  
Rock Samples ◽  
Halogenated Hydrocarbon ◽  
Liquid Saturation ◽  
Gas Pressures

HURD, B.G., SOCONY MOBIL OIL CO., INC., DALLAS, TEX. Abstract A liquid-Freon permeameter suitable for making routine permeability determinations on small plug samples is described. The instrument is characterized by simplicity of design and ease of operation, and can be assembled inexpensively from stock items of laboratory equipment. It combines the unique advantages of both liquid and gas permeameters while eliminating many undesirable features of both general classes of instruments. Precision and accuracy of the specific Freon permeability measurements compare favorably with results of conventional liquid and gas permeameters. Introduction The liquid-Freon permeameter described in this paper was designed and built for special investigations of the properties of petroleum reservoir rocks. However, its unique advantages over conventional gas and liquid permeameters make it eminently suitable for routine use in the core analysis of small plug samples. In general, gas permeameters are very popular because of their simplicity of design and ease of operation. However, apparent gas permeabilities are normally higher than true specific permeabilities unless special corrections for gas-slippage are applied. Since these corrections require two or more measurements at different internal gas pressures, much of the time advantage of the specific gas permeability measurements is lost. Liquid permeability measurements, on the other hand, require no slip correction, but liquid saturation of the sample is time-consuming and difficult to insure. Often, too, the saturating liquid must be extracted or dried from the plug before it can be used for another experiment. The liquid Freon permeameter described herein retains the inherent accuracy of the liquid permeameter, while affording the speed and ease of operation of the gas permeameter. Freon-12 (dichlorodifluoromethane) is a halogenated hydrocarbon, immiscible in the liquid phase with water. It may be considered as an oil phase in laboratory fluid-flow studies. Like butane and propane, it is a gas at normal room temperatures and atmospheric pressure but can be liquefied at moderate pressures. Complete liquid saturation of a plug sample with any of these fluids can be easily achieved by condensing vapors in the sample and operating the permeameter at a pressure above the vapor pressure of the liquid. Freon-12 is superior to butane or propane for permeability measurements only in that it is relatively non toxic and completely incombustible, and thus presents no fire or explosion hazard. Freon-12 is believed to be completely nonreactive with most petroleum-reservoir rock samples. It volatilizes immediately from a plug on depressurizing to leave a clean, dry sample suitable for subsequent experiments. Thus, the inherent risk of changing physical properties of rock samples by cleaning and drying operations between permeability measurement and subsequent experiments is eliminated. DESCRIPTION OF THE PERMEAMETER The design of the liquid Freon permeameter is shown schematically in Fig. 1. SPEJ P. 18^

TOTAL POROSITY AND MATRIX PARAMETERS OF CARBONATE ROCKS BASED ON THE ELASTIC WAVE VELOCITY AND DENSITY MEASUREMENTS

2018 ◽  
Vol 473 (473) ◽  
pp. 13-26
Author(s):  
Jadwiga JARZYNA ◽  
Edyta PUSKARCZYK ◽  
Ewa OGÓREK ◽  
Jacek MOTYKA
Keyword(s):  
Elastic Wave ◽  
Elastic Waves ◽  
Total Porosity ◽  
Elastic Wave Velocity ◽  
P Wave ◽  
Reservoir Properties ◽  
Rock Samples ◽  
Additional Information ◽  
Wave Velocities ◽  
Boundary Velocity

The purpose of the research was to find relationship between elastic waves velocities obtained from lab measurements and parameters from hydrogeological research. Measurements were conducted on 73 rock samples originating mostly from Jurassic limestone of the Olkusz area. Additional information about the rock samples was obtained when the elastic wave velocities were compared with reservoir parameters such as porosity, permeability and density. Plots of elastic waves velocities vs. porosity and bulk density vs. porosity gave information about the range of P wave velocities from the boundary velocity to the values when porosity is equal to zero. Matrix velocity and density values were introduced into the formulas used to calculate porosity. Anisotropy analysis was made on the basis of elastic wave velocities measured on cores cut in two perpendicular directions. This allowed for identification of fractures in rocks. Results showed that by comparing various petrophysical parameters it was possible to get better information about reservoir properties of aquifers.

scholarly journals A Practical Method to Calculate and Model the Petrophysical Properties of Reservoir Rock Using Petrel Software: A case Study from Iraq

2020 ◽  
pp. 2640-2650
Author(s):  
Sarah Taboor Wali ◽  
Hussain Ali Baqer
Keyword(s):  
Water Saturation ◽  
Three Dimensional ◽  
Carbonate Reservoir ◽  
Reservoir Rock ◽  
Sequential Gaussian Simulation ◽  
Geological Model ◽  
Petrophysical Properties ◽  
Reservoir Properties ◽  
Software Models ◽  
Average Water

Nasiriyah oilfield is located in the southern part of Iraq. It represents one of the promising oilfields. Mishrif Formation is considered as the main oil-bearing carbonate reservoir in Nasiriyah oilfield, containing heavy oil (API 25o(. The study aimed to calculate and model the petrophysical properties and build a three dimensional geological model for Mishrif Formation, thus estimating the oil reserve accurately and detecting the optimum locations for hydrocarbon production. Fourteen vertical oil wells were adopted for constructing the structural and petrophysical models. The available well logs data, including density, neutron, sonic, gamma ray, self-potential, caliper and resistivity logs were used to calculate the petrophysical properties. The interpretations and environmental corrections of these logs were performed by applying Techlog 2015 software. According to the petrophysical properties analysis, Mishrif Formation was divided into five units (Mishrif Top, MA, shale bed, MB1 and MB2).    A three-dimensional geological model, which represents an entrance for the simulation process to predict reservoir behavior under different hydrocarbon recovery scenarios, was carried out by employing Petrel 2016 software. Models for reservoir characteristics (porosity, permeability, net to gross NTG and water saturation) were created using the algorithm of Sequential Gaussian Simulation (SGS), while the variogram analysis was utilized as an aid to distribute petrophysical properties among the wells.      The process showed that the main reservoir unit of Mishrif Formation is MB1 with a high average porosity of 20.88% and a low average water saturation of 16.9%. MB2 unit has good reservoir properties characterized by a high average water saturation of 96.25%, while MA was interpreted as a water-bearing unit. The impermeable shale bed unit is intercalated between MA and MB1 units with a thickness of 5-18 m, whereas Mishrif top was interpreted as a cap unit. The study outcomes demonstrated that the distribution accuracy of the petrophysical properties has a significant impact on the constructed geological model which provided a better understanding of the study area’s geological construction. Thus, the estimated reserve h was calculated to be about 7945 MSTB. This can support future reservoir development plans and performance predictions. 

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.

3D Numerical Mineral Mechanical Modeling of Fracture Propagation in Complex Reservoirs Rocks at Microscale

2021 ◽  
Author(s):  
Victor Nachev ◽  
Sergey Turuntaev
Keyword(s):  
Fracture Propagation ◽  
Space Structure ◽  
Image Correlation ◽  
Reservoir Rock ◽  
Void Space ◽  
Stress Strain ◽  
Validation Data ◽  
Rock Samples ◽  
Tight Gas Reservoir ◽  
Secondary Fractures

<p>Improved efficiency of hydraulic fracturing (HF) operations in complex reservoir rocks requires producing an extensive network of secondary fractures alongside the main fractures. The goal of the presented research is to find optimal stress-strain conditions yielding the most extensive network of secondary fractures at the microscale. The scope includes integrating results of microstructural characterization of tight gas reservoir rock samples and geomechanics. The study addresses the problem of hydraulic fracture optimization by suggesting stress-strain conditions to maximize fracture branching and, therefore, to optimize the drainage zone. We use a multidisciplinary approach including experimental data obtaining and numerical simulations. The first step is preparing a consistent set of 2D and 3D digital rock (DR) microscale models describing the experimental geometry, mineral composition and spatial distribution of mechanical properties of real rock samples. Geomechanical and petrophysical laboratory testing provide calibration/validation data for the DR models. Lab experiments include compressive and tensile strength testing coupled with digital image correlation, and X-ray computed tomography, 2D scanning electron microscopy coupled with mineralogy mapping. The preparation of DR models involves advanced 2D-to-3D and 3D-to-3D image registration techniques. The second step is a simulation of stress-strain states and fracture propagation in the models. We build simulation grids based on the mineral model and use a commercial mechanical simulator to simulate the fracture propagation at a microscale at given stress conditions. We applied the above approach to one of the most promising gas formations located in West Siberia, Russia. The reservoir rock features low permeability and pore dimensions down to tens of nanometers. Simulations delivered fracture networks for different loading conditions at the microscale. Simulation of typical geomechanical conditions allowed choosing reasonable stress-strain conditions that sustain the highest degree of formation fracturing. The research results may be applied to unconventional plays by increasing the efficiency of HF operation and maximizing production from isolated pore systems via establishing voids connectivity in the near-wellbore zone. The knowledge of the optimal stress-strain state for a near-wellbore zone will set the goal for HF propagation modeling at a wellbore scale. Using the approach, a geomechanical modeler would focus on designing main fractures, sustaining required stress-strain conditions in its vicinity, and thus producing the maximal amount of secondary microfractures. The results novelty is related with the simulation of 3D fracture propagation in highly heterogeneous reservoirs rocks taking into account its void space structure and fabric in geometry closest to real conditions.</p>

scholarly journals Digital Rock Samples Porosity Analysis by OTSU Thresholding Technique Using MATLAB

2020 ◽  
Vol 21 (3) ◽  
pp. 57-66
Author(s):  
Yahya Jirjees Tawfeeq ◽  
Jalal A. Al-Sudani
Keyword(s):  
Image Processing ◽  
Pore Structure ◽  
Thin Section ◽  
Digital Image ◽  
Carbonate Reservoir ◽  
Oil Field ◽  
Reservoir Rock ◽  
Reservoir Rocks ◽  
Rock Samples ◽  
Digital Rock

Porosity plays an essential role in petroleum engineering. It controls fluid storage in aquifers, connectivity of the pore structure control fluid flow through reservoir formations. To quantify the relationships between porosity, storage, transport and rock properties, however, the pore structure must be measured and quantitatively described. Porosity estimation of digital image utilizing image processing essential for the reservoir rock analysis since the sample 2D porosity briefly described. The regular procedure utilizes the binarization process, which uses the pixel value threshold to convert the color and grayscale images to binary images. The idea is to accommodate the blue regions entirely with pores and transform it to white in resulting binary image. This paper presents the possibilities of using image processing for determining digital 2D rock samples porosity in carbonate reservoir rocks. MATLAB code created which automatically segment and determine the digital rock porosity, based on the OTSU's thresholding algorithm. In this work, twenty-two samples of 2D thin section petrographic image reservoir rocks of one Iraqi oil field are studied. The examples of thin section images are processed and digitized, utilizing MATLAB programming. In the present study, we have focused on determining of micro and macroporosity of the digital image. Also, some pore void characteristics, such as area and perimeter, were calculated. Digital 2D image analysis results are compared to laboratory core investigation results to determine the strength and restrictions of the digital image interpretation techniques. Thin microscopic image porosity determined using OTSU technique showed a moderate match with core porosity.

Decision Criterion for Acid-Stimulation Method in Carbonate Reservoirs: Matrix Acidizing or Acid Fracturing?

SPE Journal ◽  
2020 ◽  
Vol 25 (05) ◽  
pp. 2296-2318
Author(s):  
Mateus Palharini Schwalbert ◽  
Murtada Saleh Aljawad ◽  
Alfred Daniel Hill ◽  
Ding Zhu
Keyword(s):  
Decision Criterion ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Reservoir Rock ◽  
Dimensionless Number ◽  
Confining Stress ◽  
Reservoir Properties ◽  
Matrix Acidizing ◽  
Acid Fracturing ◽  
Stimulation Method

Summary Most wells in carbonate reservoirs are stimulated. Because of their low cost and simpler operations, acid-stimulation methods are usually preferred if they are sufficient. Matrix acidizing can effectively stimulate carbonate reservoirs, often resulting in skin factors on the order of −3 to −4. In low confining stress and hard rocks, acid fracturing can yield better results than matrix acidizing. However, acid fracturing is less effective in high permeability, high confining stress, or soft rocks. There is a combination of parameters, among them permeability, confining stress, and rock geomechanical properties, that can be used as criteria to decide whether matrix acidizing or acid fracturing is the best acid-stimulation technique for a given scenario. This study compares the productivity of matrix-acidized and acid-fractured wells in carbonate reservoirs. The criterion used to decide the preferred method is the largest productivity obtained using the same volume of acid for both operations. The productivity of the acid-fractured wells is estimated using a fully coupled acid-fracturing simulator, which integrates the geomechanics (fracture propagation), pad and acid transport, heat transfer, temperature effect on reaction rate, effect of wormhole propagation on acid leakoff, and finally calculates the well productivity by simulating the flow in the reservoir toward the acid fracture. Using this simulator, the acid-fracturing operation is optimized, resulting in the operational conditions (injection rate, type of fluid, amount of pad, and so forth) that lead to the best possible acid fracture that can be created with a given amount of acid. The productivity of the matrix-acidized wells is estimated using the most recent wormhole-propagation models scaled up to field conditions. Results are presented for different types of rock and reservoir scenarios, such as shallow and deep reservoirs, soft and hard limestones, chalks, and dolomites. Most of the presented results considered vertical wells. A theoretical extension to horizontal wells is also presented using analytical considerations. For each type of reservoir rock and confining stress, there is a cutoff permeability less than which acid fracturing results in a more productive well; at higher than this cutoff permeability, matrix acidizing should be preferred. This result agrees with the general industry practice, and the estimated productivity agrees with the results obtained in the field. However, the value of the cutoff permeability changes for each case, and simple equations for calculating it are presented. For example, for harder rocks or shallower reservoirs, acid fracturing is more efficient up to higher permeabilities than in softer rocks or at deeper depths. This method provides an engineered criterion to decide the best acid-stimulation method for a given carbonate reservoir. The decision criterion is presented for several different scenarios. A simplified concise analytical decision criterion is also presented: a single dimensionless number that incorporates all pertinent reservoir properties and determines which stimulation method yields the most productive well, without needing any simulations.

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