scholarly journals Integrated petroelectrical models of devonian limestones and cambrian sandstones from Dobrotvirska area of Volyno-Podilia

2014 ◽  
pp. 25-30
Author(s):  
S. Vyzhva ◽  
D. Onyshchuk ◽  
N. Reva ◽  
V. Onyshchuk
Keyword(s):  
Water Saturation ◽  
Laboratory Data ◽  
Effective Porosity ◽  
P Wave ◽  
Rock Properties ◽  
Residual Water ◽  
Specific Resistivity ◽  
Filtration Method ◽  
Reservoir Rocks ◽  
In Situ Conditions

This paper deals with the technique and results of research into petroelectrical properties of complex terrigenous and carbonate reservoirs. Analyzed are electric data and their relation to capacity properties of Devonian limestones and Cambrian sandstones from Dobrotvirska area of Volyno-Podilia. The objective of the research was to build petroelectrical models of reservoir rocks based on the electrical parameters and their relation to capacity properties. Data on specific resistivity of reservoir rocks were used for specifying the range of its variation for different types and groups of rocks. These data were also essential for identifying the stratigraphic horizons, cross-sections and facies, as well as finding the relationship between specific resistivity and a range of factors such as mineral composition, pore structure, substance phase ratio, electric field intensity and frequency, and resistivity variations with epigenetic transformation and metamorphic changes in rocks. Laboratory data on electrical resistivity of rocks made it possible to interpret the results of employing electrometric well logging methods and electric exploration. Petrophysical laboratory data enabled us to determine the following properties: rock density (dry and saturated with synthetic brine), effective porosity (nitrogen and synthetic brine saturation methods), residual water saturation factor (by centrifugation), permeability (nitrogen stationary filtration method), interval time (P-wave velocity) and resistivity. There were obtained laboratory data on specific resistivity of rock samples (dry, partly and fully saturated with synthetic brine) in atmospheric and in simulated in-situ conditions. We estimated the petroelectrical parameters of Cambrian sandstones and Devonian limestones from Dobrotvirska area to find an empirical correlation between petroelectrical parameters, porosity and permeability of the studied rocks. The correlations are mainly approximated by power function and serve as the basis for geological interpretation of geophysical data. Electrometric methods have proved to be a powerful tool in both laboratory and field rock studies, being efficient enough to provide extensive information on rock properties.

Residual Water Saturation of Source Rocks of the Bazhenov Formation Western Siberia, Russia

2021 ◽  
Author(s):  
Anton Vasilievich Glotov ◽  
Anton Gennadyevich Skripkin ◽  
Petr Borisovich Molokov ◽  
Nikolay Nilovich Mikhailov
Keyword(s):  
Western Siberia ◽  
Water Saturation ◽  
Source Rocks ◽  
Rock Properties ◽  
Low Permeability ◽  
Residual Water ◽  
Bazhenov Formation ◽  
Rock Formation ◽  
Low Permeability Reservoirs ◽  
Significant Underestimation

Abstract The article presents a new method of determining the residual water saturation of the Bazhenov Rock Formation using synchronous thermal analysis which is combined with gas IR and MS spectroscopy. The efficiency of the extraction-distillation method of determining open porous and residual saturation in comparison with the developed method which are considered in detail. Based on the results of studies in the properties of the Bazhenov Rock Formation, a significant underestimation of the residual water saturation in the existing guidelines for calculating reserves was found, and the structure of the saturation of rocks occurred to be typical for traditional low-permeability reservoirs. The values of open porous and residual water saturation along the section of the Bazhenov Formation vary greatly, which also contradicts the well-established opinion about the weak variability of the rock properties with depth.

Incorporating mechanisms of fluid pressure relaxation into inclusion‐based models of elastic wave velocities

Geophysics ◽  
2003 ◽  
Vol 68 (4) ◽  
pp. 1173-1181 ◽  
Author(s):  
S. Richard Taylor ◽  
Rosemary J. Knight
Keyword(s):  
Elastic Wave ◽  
Water Saturation ◽  
Laboratory Data ◽  
Fluid Pressure ◽  
P Wave ◽  
Porous Rocks ◽  
Low Frequencies ◽  
Wave Velocities ◽  
Exact Agreement ◽  
Flow Through

Our new method incorporates fluid pressure communication into inclusion‐based models of elastic wave velocities in porous rocks by defining effective elastic moduli for fluid‐filled inclusions. We illustrate this approach with two models: (1) flow between nearest‐neighbor pairs of inclusions and (2) flow through a network of inclusions that communicates fluid pressure throughout a rock sample. In both models, we assume that pore pressure gradients induce laminar flow through narrow ducts, and we give expressions for the effective bulk moduli of inclusions. We compute P‐wave velocities and attenuation in a model sandstone and illustrate that the dependence on frequency and water‐saturation agrees qualitatively with laboratory data. We consider levels of water saturation from 0 to 100% and all wavelengths much larger than the scale of material heterogeneity, obtaining near‐exact agreement with Gassmann theory at low frequencies and exact agreement with inclusion‐based models at high frequencies.

scholarly journals PREDIKSI PERMEABILITAS MENGGUNAKAN METODE LOG DAN PORE GEOMETRY STRUCTURE (PGS) PADA DAERAH CEKUNGAN JAWA BARAT UTARA

2020 ◽  
Vol 6 (1) ◽  
pp. 3-17
Author(s):  
Ayu Yuliani ◽  
Ordas Dewanto ◽  
Karyanto Karyanto ◽  
Ade Yogi
Keyword(s):  
Water Saturation ◽  
Effective Porosity ◽  
Reservoir Rock ◽  
Rock Properties ◽  
Pore Geometry ◽  
Rock Permeability ◽  
Zone Formation ◽  
Geometry Structure ◽  
Rock Typing

Determination of reservoir rock properties is very important to be able to understand the reservoir better. One of these rock properties is permeability. Permeability is the ability of a rock to pass fluid. In this study, the calculation of permeability was carried out using log and PGS (Pore Geometry Structure) methods based on core data, logs, and CT scans. In the log method, the calculation of permeability is done by petrophysical analysis which aims to evaluate the target zone formation in the form of calculation of the distribution of shale content (effective volume), effective porosity, water saturation, and permeability. Next, the determination of porosity values from CT Scan. Performed on 2 data cores of 20 tubes, each tube was plotted as many as 15 points. The output of this stage is the CT Porosity value that will be used for the distribution of predictions of PGS permeability values. In the PGS method, rock typing is based on geological descriptions, then calculation of permeability predictions. Using these two methods, permeability can be calculated in the study area. The results of log and PGS permeability calculations that show good correlation are the results of calculation of PGS permeability. It can be seen from the data from the calculation of PGS permeability approaching a gradient of one value with R2 of 0.906, it will increasingly approach the core rock permeability value. Whereas the log permeability calculation for core rock permeability is 0.845.

Acoustic signature of fluid substitution in reservoir rocks

2020 ◽  
Author(s):  
Christian David ◽  
Joël Sarout ◽  
Christophe Barnes ◽  
Jérémie Dautriat ◽  
Lucas Pimienta
Keyword(s):  
Wave Velocity ◽  
Water Injection ◽  
P Wave ◽  
Rock Properties ◽  
Fluid Distribution ◽  
Fluid Substitution ◽  
Ultrasonic Monitoring ◽  
Reservoir Rocks ◽  
Water Imbibition ◽  
P Wave Velocity

<p>During the production of hydrocarbon reservoirs, EOR operations, storage of CO2 underground or geothermal fluid exchanges at depth, fluid substitution processes can lead to significant changes in rock properties which can be captured from the variations in seismic waves attributes. In the laboratory, fluid substitution processes can be investigated using ultrasonic monitoring. </p><p>The motivation of our study was to identify the seismic attributes of fluid substitution in reservoir rocks through a direct comparison between the variation in amplitude, velocity, spectral content, energy, and the actual fluid distribution in the rocks. Different arrays of ultrasonic P-wave sensors were used to record at constant time steps the waveforms during fluid substitution experiments. Two different kinds of experiments are presented: (i) water injection experiments in oil-saturated samples under stress in a triaxial setup mimicking EOR operations, (ii) spontaneous water imbibition experiments at room conditions.</p><p>In the water injection tests on a poorly consolidated sandstone saturated with oil and loaded at high deviatoric stresses, water weakening triggers mechanical instabilities leading to the rock failure. The onset of such instabilities can be followed with ultrasonic monitoring either in the passive mode (acoustic emissions recording) or in the active mode (P wave velocity survey).</p><p>In the water imbibition experiments, a methodology based on the analytical signal and instantaneous phase was designed to decompose each waveform into discrete wavelets associated with direct or reflected waves. The energy carried by the wavelets is very sensitive to the fluid substitution process: the coda wavelets are impacted as soon as imbibition starts and can be used as a precursor for remote fluid substitution. It is also shown that the amplitude of the first P-wave arrival is impacted by the upward moving fluid front before the P-wave velocity is. Several scenarios are discussed to explain the decoupling between P wave amplitude and velocity variations during fluid substitution processes.</p>

scholarly journals P<sup>3</sup> – PetroPhysical Property Database – a global compilation of lab measured rock properties

2020 ◽  
Author(s):  
Kristian Bär ◽  
Thomas Reinsch ◽  
Judith Bott
Keyword(s):  
Numerical Models ◽  
Laboratory Data ◽  
Rock Properties ◽  
Petrophysical Properties ◽  
Geophysical Investigation ◽  
Geothermal Exploration ◽  
Accessible Information ◽  
In Situ Conditions ◽  
Investigation Methods ◽  
Geophysical Surveys

Abstract. Petrophysical properties are key to populate local and/or regional numerical models and to interpret results from geophysical investigation methods. Searching for rock property values measured on samples from a specific rock unit at a specific location might become a very time-consuming challenge given that such data are spread across diverse compilations and that the number of publications on new measurements is continuously growing and data are of heterogeneous quality. Profiting from existing laboratory data to populate numerical models or interpret geophysical surveys at specific locations or for individual reservoir units is often hampered if information on the sample location, petrography, stratigraphy, measuring method and conditions are sparse or not documented. Within the framework of the EC funded project IMAGE (Integrated Methods for Advanced Geothermal Exploration, EU grant agreement No. 608553), an open-access database of lab measured petrophysical properties has been developed (Bär et al., 20182019: P3 – Database, https://doi.org/10.5880/GFZ.4.8.2019.P3). The goal of this hierarchical database is to provide easily accessible information on physical rock properties relevant for geothermal exploration and reservoir characterization in a single compilation. Collected data include classical petrophysical, thermophysical and mechanical properties and, in addition, electrical conductivity and magnetic susceptibility. Each measured value is complemented by relevant meta-information such as the corresponding sample location, petrographic description, chronostratigraphic age, if available, and original citation. The original stratigraphic and petrographic descriptions are transferred to standardized catalogues following a hierarchical structure ensuring inter-comparability for statistical analysis (Bär et al., 2019: P3 – Petrography, https://doi.org/10.5880/GFZ.4.8.2019.P3.p, Bär et al., 20182019: 3 – Stratigraphy, https://doi.org/10.5880/GFZ.4.8.2019.P3.s. In addition, information on the experimental setup (methods) and the measurement conditions are listed for quality control. Thus, rock properties can directly be related to in-situ conditions to derive specific parameters relevant for simulating subsurface processes or interpreting geophysical data. We describe the structure, content and status quo of the database and discuss its limitations and advantages for the end-user.

scholarly journals The PetroPhysical Property Database (P<sup>3</sup>) – a global compilation of lab-measured rock properties

2020 ◽  
Vol 12 (4) ◽  
pp. 2485-2515
Author(s):  
Kristian Bär ◽  
Thomas Reinsch ◽  
Judith Bott
Keyword(s):  
Numerical Models ◽  
Laboratory Data ◽  
Rock Properties ◽  
Petrophysical Properties ◽  
Geophysical Investigation ◽  
Geothermal Exploration ◽  
Accessible Information ◽  
In Situ Conditions ◽  
Investigation Methods ◽  
Geophysical Surveys

Abstract. Petrophysical properties are key to populating local and/or regional numerical models and to interpreting results from geophysical investigation methods. Searching for rock property values measured on samples from a specific rock unit at a specific location might become a very time-consuming challenge given that such data are spread across diverse compilations and that the number of publications on new measurements is continuously growing and data are of heterogeneous quality. Profiting from existing laboratory data to populate numerical models or interpret geophysical surveys at specific locations or for individual reservoir units is often hampered if information on the sample location, petrography, stratigraphy, measuring method and conditions is sparse or not documented. Within the framework of the EC-funded project IMAGE (Integrated Methods for Advanced Geothermal Exploration, EU grant agreement no. 608553), an open-access database of lab-measured petrophysical properties has been developed (Bär et al., 2017, 2019b: P3 – database, https://doi.org/10.5880/GFZ.4.8.2019.P3. The goal of this hierarchical database is to provide easily accessible information on physical rock properties relevant for geothermal exploration and reservoir characterisation in a single compilation. Collected data include classical petrophysical, thermophysical, and mechanical properties as well as electrical conductivity and magnetic susceptibility. Each measured value is complemented by relevant meta-information such as the corresponding sample location, petrographic description, chronostratigraphic age, if available, and original citation. The original stratigraphic and petrographic descriptions are transferred to standardised catalogues following a hierarchical structure ensuring inter-comparability for statistical analysis (Bär and Mielke, 2019: P3 – petrography, https://doi.org/10.5880/GFZ.4.8.2019.P3.p; Bär et al., 2018, 2019a: P3 – stratigraphy, https://doi.org/10.5880/GFZ.4.8.2019.P3.s). In addition, information on the experimental setup (methods) and the measurement conditions are listed for quality control. Thus, rock properties can directly be related to in situ conditions to derive specific parameters relevant for simulating subsurface processes or interpreting geophysical data. We describe the structure, content and status quo of the database and discuss its limitations and advantages for the end user.

scholarly journals Discrepancy between measured dynamic poroelastic parameters and predicted values from Wyllie’s equation for water-saturated Istebna sandstone

2021 ◽  
Author(s):  
Dariusz Knez ◽  
Herimitsinjo Rajaoalison
Keyword(s):  
Young’S Modulus ◽  
Poisson’S Ratio ◽  
Young's Modulus ◽  
Laboratory Data ◽  
Confining Pressure ◽  
P Wave ◽  
Poisson's Ratio ◽  
Rock Properties ◽  
Biot’S Coefficient ◽  
Water Saturated

AbstractThe drilling-related geomechanics requires a better understanding of the encountered formation properties such as poroelastic parameters. This paper shows set of laboratory results of the dynamic Young’s modulus, Poisson’s ratio, and Biot’s coefficient for dry and water-saturated Istebna sandstone samples under a series of confining pressure conditions at two different temperatures. The predicted results from Wyllie’s equation were compared to the measured ones in order to show the effect of saturation on the rock weakening. A negative correlation has been identified between Poisson’s ratio, Biot’s coefficient and confining pressure, while a positive correlation between confining pressure and Young’s modulus. The predicted dynamic poroelastic rock properties using the P-wave value from Wyllie’s equation are different from measured ones. It shows the important influence of water saturation on rock strength, which is confirmed by unconfined compressive strength measurement. Linear equations have been fitted for the laboratory data and are useful for the analysis of coupled stress and pore pressure effects in geomechanical problems. Such results are useful for many drilling applications especially in evaluation of such cases as wellbore instability and many other drilling problems.

scholarly journals POROSITY AND PERMEABILITY PROPERTIES OF CONSOLIDATED ROCKS OF THE NORTHERN NEAR EDGE ZONE OF THE DNIEPER-DONETSK DEPRESSION

2021 ◽  
pp. 37-45
Author(s):  
S. Vyzhva ◽  
V. Onyshchuk ◽  
I. Onyshchuk ◽  
M. Reva ◽  
O. Shabatura
Keyword(s):  
Permeability Coefficient ◽  
Water Saturation ◽  
Effective Porosity ◽  
Integrated Analysis ◽  
Residual Water ◽  
Edge Zone ◽  
Reservoir Conditions ◽  
Porosity Coefficient ◽  
Porosity And Permeability ◽  
Saturation Factor

Paper concerned the researches of porosity and permeability properties of consolidated rocks (siltstones, poor-porous sandstones) of the northern near edge zone of the Dnieper-Donetsk depression. The purpose of the research was to study the petrophysical parameters of the consolidated reservoir rocks, as the basis of the integrated analysis of their physical properties. Such reservoir parameters as the open porosityfactor and void factor, permeability coefficient and residual water saturation factor were studied. Void structure of rocks with capillarimetric method was studied. The relationship of the density of rocks with their porosity was also studied. The porosity study was carried out in atmospheric and reservoir conditions. The bulk density of dry rock samples varies: for siltstones from 2232 kg/m3 to 2718 kg/m3 (mean 2573 kg/m3 ), for sandstones from 2425 kg/m3 to 2673 kg/m3 (mean 2555 kg/m3); water saturated rocks – for siltstones from 2430 to 2727 kg/m3 (mean 2622 kg/m3 ), for sandstones from 2482 kg/m3 to 2688 kg/m3 (mean 2599 kg/m3 ). An apparent specific matrix density varies: for siltstones from 2645 to 2740 kg/m3 (mean 2683 kg/m3 ), for sandstones from 2629 kg/m3 to 2730 kg/m3 (mean 2664 kg/m3). The open porosity coefficient of studied rocks, in a case they were saturated with the synthetic brine, varies: for siltstones from 0,008 to 0,074 (mean 0,034), for sandstones from 0,013 to 0,087 (mean 0,041), if samples were saturated with nitrogene (N2) then it varies: for siltstones from 0,013 to 0,076 (mean 0,040), for sandstones from 0,022 to 0.095 (mean 0.052). The effective porosity factor has following values: for siltstones 0,0003–0,0050 (mean 0,00026), for sandstones 0,0013–0,0293 (mean 0,0048). Analysis of reservoir conditions modeling revealed that porosity coefficient varies: for siltstones from 0,007 to 0,060 (mean 0,028), for consolidated sandstones from 0,011 to 0,081 (mean 0,037). Due to the closure of microcracks under rock loading reduced to reservoir conditions the porosity decreases in comparison with atmospheric conditions, which causes a relative decrease in the porosity coefficient for siltstones from 14 to 19,5 % (mean 17,0 %), for sandstones from 7,5 to 18.0 % (mean 10,5 %). Capillaryometric studies by centrifuging determined that the void space of the studied rocks has the following structure: for siltstones, the content of hypercapillary pores varies from 1 to 6 % (mean 3 %); the content of capillary pores – from 1 to 11 % (mean 5 %), the content of subcapillary pores – from 84 to 97 % (mean 92 %); for sandstones, the content of hypercapillary pores varies from 1 to 18 % (mean 4%); content of capillary pores – from 2 to 40 % (mean 10 %), the content of subcapillary pores – from 43 to 96 % (mean 86 %). According to the results of laboratory measurements of the permeability coefficient, this parameter varies: for siltstones from 0,002 fm2 to 1,981 fm2 (mean 0,279 fm2 ), for sandstones from 0,002 fm2 to 1,492 fm2 (mean 0,176 fm2 ). The correlation analysis has allowed to establish a series of empirical relationships between the reservoir parameters (density, porosity coefficient, permeability coefficient, effective porosity factor and residual water saturation factor). These relationships can be used in the data interpretation of geophysical studies of wells and in the modeling of the porosity and permeability properties of consolidated rocks of the northern near edge zone of the Dnieper-Donetsk depression.

scholarly journals Comparative Characterization of Petrophysical and Mechanical Properties of Siliciclastic Reservoir Rocks within a compressional structure of the Teapot Dome Oilfield, Wyoming, USA

2020 ◽  
Vol 5 (2) ◽  
pp. 1-12
Author(s):  
Rotimi Oluwatosin John ◽  
Ogunkunle Fred Temitope ◽  
Onuh Charles Yunusa ◽  
Ameloko Aduojo Anthony ◽  
Enaworu Efeoghene ◽  
...  
Keyword(s):  
Mechanical Properties ◽  
Seismic Data ◽  
Water Saturation ◽  
Accurate Determination ◽  
Hydrocarbon Exploration ◽  
Rock Properties ◽  
Petrophysical Properties ◽  
Fluid Movement ◽  
Property Variation ◽  
Reservoir Rocks

AbstractWorking with subsurface engineering problems in Hydrocarbon exploration as regard rock elastic and petrophysical properties necessitate accurate determination of in-situ physical properties. Several techniques have been adopted in correlating log-derived parameters with petrophysical and mechanical behavior of the rocks. However, limited field applications show there are no particular parameters and correlations that are generally acceptable due to the regional variation in geologic features (i.e., degree of mineralogy, texture, etc.). This study presents a method that assesses the disparity in petrophysical properties of oil and gas reservoir rocks in relation to their elastic/mechanical properties from 10 well-logs and 3D migrated seismic data. Two distinct facies were identified from seismic data after computing attributes. Reflection strength attribute of 2.5 and above depicts Bright spots within the central section of the field as clearly revealed by Variance and Chaos attributes. Formation properties calculated from logs were conformally gridded in consonance with the reflection patterns from the seismic data. The average Brittleness index (BI) of 0.52 corresponds to Young’s modulus (E) values of between 8 and 16 for the dense portion. This portion is the laminated, reasonably parallel, and undeformed part, flanked by the unlaminated and chaotic zones. From cross plots, the distinguished lower portion on the plot is the segment with higher sand of more than 50 %. This segment corresponds to the reservoir in this study as confirmed from the genetic algorithm neural network Acoustic impedance inversion process result. Similarly, the plot of Compressional velocity (Vp) and Poisson’s ratio (ν), reveals the laminated sand value of not less than 0.32 of ν, and Vp of about 4.2 km/s. The average porosity is about 16 %, average water saturation is about 16 %, and average permeability is approximately 25 md. Rock properties trends in a unique pattern and showing fluctuation that confirms the compressive nature of the structure with corresponding petrophysical properties. This trend is sustained in permeability computed and suggests a significant gravity-assisted compaction trend and fluid movement. It gives a reasonable idea of the fluid movement interplay and mechanical property variation within the sequence and across the dome. This part probably has been subjected to fair compressional deformational forces initiated from outside the survey.

Attenuation of P‐ and S‐waves as a method of distinguishing gas and condensate from oil and water

Geophysics ◽  
1995 ◽  
Vol 60 (2) ◽  
pp. 447-458 ◽  
Author(s):  
Theodoros Klimentos
Keyword(s):  
Quality Factor ◽  
Wave Attenuation ◽  
Strong Dependence ◽  
Laboratory Data ◽  
P Wave ◽  
Seismic Exploration ◽  
S Wave ◽  
Text Quality ◽  
In Situ Conditions ◽  
Oil Water

Compressional‐ and shear‐wave attenuation data were calculated from sonic waveforms in three wells. The results show that at similar porosities and at in‐situ conditions, gas and condensate sandstone reservoirs exhibit higher P‐wave attenuation (lower P‐wave quality factor, [Formula: see text]) than either fully‐water or partially “oil + water” saturated sandstones. However, S‐wave attenuation and quality factor [Formula: see text] do not show such a strong dependence on pore fluids. Furthermore, [Formula: see text] indicates presence of gas or condensate, while [Formula: see text] indicates “full water” or “oil + water” saturation. These field data are consistent with laboratory data and theoretical predictions by various researchers. The crossovers of P-S‐wave attenuation and [Formula: see text] quality factors proved useful for distinguishing gas and condensate from oil and water reservoirs. They may be used in conjunction with [Formula: see text] and other logs as an aid in formation evaluation for the detection of gas, condensate, and oil. Several case studies in the literature report high P‐wave energy absorption at seismic frequencies below gas and condensate pools. This suggests that it is not unreasonable to assume that this method could also be used in seismic exploration as an aid for distinguishing gas and condensate from oil and water formations.

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