Reservoir Rock Properties Research Articles

The effect of sufficient barrier layers on hydraulic fracturing design efficiency in one of the Iranian South hydrocarbon reservoirs

Hydraulic fracturing and matrix stimulation are two major methods of the reservoir stimulation. Hydraulic fracturing, which is the newest technique and technically more complex, is very useful in low permeability reservoirs. Although it has been used widely in hydrocarbon production wells, it is a new method in Iran. In this paper, the effect of sufficient barrier layers on hydraulic fracturing design efficiency was done for Bangestan reservoir (one of hydrocarbon reservoirs in south of Iran). To do this, at first, mechanical earth model (MEM) was developed. This model comprise of in situ stresses and physical properties of reservoir rock (like porosity and water saturation obtained from petrophysical well logs analysis) and determination of the rock fracture pressures and fracture propagation. Then, zone 5 and Sarvak zone of Bangestan reservoir were selected as candidate layers for hydraulic fracturing modelling. Finally, hydraulic fracture was designed for selected layers. In this design, the created fracture length in zone 5 is very shorter than the created fracture length in Sarvak zone. The results show that hydraulic fracturing can be done in Sarvak zone more successful than zone 5, which shows the importance of sufficient barrier layers in hydraulic fracture efficiency.

Effects of Water and scCO2 Injection on the Mechanical Properties of Granite at High Temperatures

Geothermal energy is an important resource to substitute for traditional fossil fuels. The mechanical properties of reservoir rock under the conditions of water and scCO2 injection at different temperatures are crucial for the safety of Enhanced Geothermal Systems. However, the effects of working fluid on the mechanical properties of granite at in situ temperatures are still rarely reported. To reveal the impact mechanisms, conventional triaxial compression experiments were conducted on granite specimens with different confining pressures (2–20 MPa), different pore fluid (10 MPa water or CO2), and different temperatures (25–150°C) in the present study. SEM analyses were applied to the specimens to determine failure surface morphologies after the experiments. The experimental results show that the effective confining pressure, pore fluid, and temperature have significant effects on the strength of granite specimens. The strength of granite increases with the increase of effective confining pressure, with similar granite strength under the same effective confining pressure (dry, water, and CO2). Temperature strengthening of granite is limited by high confining pressure (∼15 MPa). Under the effective confining pressure of 5 MPa, temperature weakening occurs on granite specimens when temperature is higher than 90°C. There is fluid diffusion in the specimens during compression. The higher viscosity of water may cause a temporary decrease in effective confining pressure, which may increase the strength of granite. The growth or formation of cracks is mainly observed in quartz and feldspar grains without short‐term chemical effects. More visible cracks are observed on the specimens and more volume of fluid is injected under CO2 injection conditions, which may be beneficial to increase the permeability of geothermal reservoir.

ON THE POSSIBILITY OF WETTABILITY ASSESSMENT OF OIL AND GAS RESERVOIRS BY THEIR MAIN COLLECTOR PROPERTIES

Problem statement. In some publications, the possibility of determining the wettability according to geophysical studies of wells (GIS), in particular, defined in the complex GIS residual water saturation or water retention capacity. As the main quantitative indicator of wettability, the thickness of the fictitious film of residual water is used. If this idea is true, then the calculation of wettability is possible and the results of determining the same parameters in the course of laboratory studies of core material. The purpose of this work is to test the proposed method for calculating wettability on the basis of data on the main reservoir properties of rocks obtained in the laboratory and to assess the possibility of practical application of this technique. Scientific and practical significance. The wettability of the rock surface is an important parameter on which the main indicators of the development of hydrocarbon deposits depend. At the moment, many oil and gas companies are experiencing difficulties in developing long-term fields. This is a breakthrough of water during water flooding, selective flooding of the wells and increased water-repellency of the reservoir in the development process. Taken together, this leads to a decrease in the rate of hydrocarbon extraction, a significant increase in flooding and, as a result, to a decrease in the final indicators of hydrocarbon recovery and significant economic losses. There are many methods of influencing the oil and gas reservoir in order to obtain a cost-effective inflow of hydrocarbons. But whatever method was used, there is a question of control and adjustment of wettability, the solution of which is impossible without determining the real relative wettability of the reservoir with water and hydrocarbons. Core material, which can determine the wettability of standard methods, is not selected enough and the possibility of calculating the wettability of GIS data could fundamentally improve the situation. Analysis of available publications on the topic. In the course of the work, the theoretical background of the proposed technique, the conclusion of the formula for calculating the thickness of the dummy film and the data on practical application given in the available works were analyzed. According to the authors of the tested method, the degree of hydrophilicity of the productive formation is qualitatively characterized by the content of residual water: the higher its content, the more hydrophilic the rock. To quantify the degree of hydrophilicity, it is proposed to use the thickness of the fictitious film of residual water on the surface of pore channels, which should increase in direct proportion to the degree of hydrophilicity and which is determined by the values of the water-holding capacity of rocks. Materials of own researches. On the basis of laboratory studies, the results of which are presented in the article, it can be argued that the values of residual water saturation with increasing hydrophilicity can both increase and decrease. The relationship between residual water saturation and wetting angle is ambiguous and should be used with great care to assess the degree of hydrophilicity of rocks. Quantification of hydrophilicity on the thickness of the dummy film of residual water is complicated by the fact that, first, to determine the film thickness for water-holding capacity is highly problematic, they are too weakly bound, and secondly, the film thickness is poorly and ambiguously connected with the wetting, which used the wetting angle, and the index "M" defined by standard methods. Perhaps it is the proposed formulas for calculating the thickness of the fictitious film and the idea can be further developed, however, at this stage to replace the direct definition of wettability on the calculation of known values of reservoir properties is impossible. Conclusion. Calculation of wettability by known values of basic reservoir properties determined in laboratory conditions is impossible. We stipulate that this conclusion cannot be unconditionally transferred to the assessment of wettability according to GIS (determination of both residual water saturation and gas saturation coefficient according to GIS has its own specifics), but the impossibility of constructing the desired connections in the laboratory forces caution to approach such calculations. The performed work will help to avoid gross errors in the assessment of wettability, performed for various practical purposes, in particular, in the development of methods to prevent selective flooding of wells.

ГЕОЛОГО-ПЕТРОФІЗИЧНА ХАРАКТЕРИСТИКА ВІДКЛАДІВ СИЛУРУ ВОЛИНО-ПОДІЛЬСЬКОЇ ОКРАЇНИ СХІДНОЄВРОПЕЙСЬКОЇ ПЛАТФОРМИ

Taking into consideration well logging of the Silurian deposits of the Volyn-Podillya plate, the materials of laboratory investigations of petrophysical parameters of reservoir rocks were analyzed and systematized. Studied were capacity-filtration properties of reservoir rocks as well as their lithological-petrographical and structural-textural features. An analysis of the distribution of petrophysical parameters of the Silurian deposits of the Volyn-Podillya plate was executed by the methods of mathematic statistics. Main statistics and correlation coefficients between individual parameters were calculated, histograms of the distribution of the porosity factor Kpor and the permeability factor Kper, volumetric weight δ and carbonation C in rocks were compiled, regression equations between parameters and their alteration with depth were formed. Petrophysical parameters of the samples available for carbonate and terrigenous rocks of Silurian were analyzed separately. Executed investigations of petrophysical properties of rocks testify that in the Silurian deposits the carbonate reservoirs with the complex structure of the porous space were distributed. A visible alteration of capacity-filtration parameters of rocks of Silurian deposits is observed with depth. Porosity of rocks decreases with depth, but permeability increases that is a confirmation of the formation of the secondary fractured-covernous porosity. Increase in the permeability factor with depth is characteristic of carbonate rocks. According to geological-geophysical data available, the reservoir rocks with better capacity-filtration properties are distributed in the zone of the barrier reef. The best reservoir parameters are characteristic of cavernous dolomites and limestones at the Lokachy area and in the region of Lutsk. Reservoir rocks of porous type are practically absent at depths over 2500 m. Here a significant role in improving of collecting properties of rocks belongs to their fracturing. Microfractures are observed in clayed limestones, marls and clay rocks. Under favourable geodynamic conditions the subvertical zones of disconsolidation occur in which composite reservoir rocks with fracture porosity may be formed.

Reservoir rock properties estimation based on conventional and NMR log data using ANN-Cuckoo: A case study in one of super fields in Iran southwest

This work highlights the application of Artificial Neural Networks optimized by Cuckoo optimization algorithm for predictions of NMR log parameters including porosity and permeability by using field log data. The NMR logging data have some highly vital privileges over conventional ones. The measured porosity is independent from bearer pore fluid and is effective porosity not total. Moreover, the permeability achieved by exact measurement and calculation considering clay content and pore fluid type. Therefore availability of the NMR data brings a great leverage in understanding the reservoir properties and also perfectly modelling the reservoir. Therefore, achieving NMR logging data by a model fed by a far inferior and less costly conventional logging data is a great privilege. The input parameters of model were neutron porosity (NPHI), sonic transit time (DT), bulk density (RHOB) and electrical resistivity (RT). The outputs of model were also permeability and porosity values. The structure developed model was build and trained by using train data. Graphical and statistical validation of results showed that the developed model is effective in prediction of field NMR log data. Outcomes show great possibility of using conventional logging data be used in order to reach the precious NMR logging data without any unnecessary costly tests for a reservoir. Moreover, the considerable accuracy of newly ANN-Cuckoo method also demonstrated. This study can be an illuminator in areas of reservoir engineering and modelling studies were presence of accurate data must be essential.

Reservoir Performance Prediction using Integrated Production Modelling (MBAL Software)

Reservoir performance prediction is important aspect of the oil & gas field development planning and reserves estimation which depicts the behavior of the reservoir in the future. Reservoir production success is dependent on precise illustration of reservoir rock properties, reservoir fluid properties, rock-fluid properties and reservoir flow performance. Petroleum engineers must have sound knowledge of the reservoir attributes, production operation optimization and more significant, to develop an analytical model that will adequately describe the physical processes which take place in the reservoir. Reservoir performance prediction based on material balance equation which is described by Several Authors such as Muskat, Craft and Hawkins, Tarner’s, Havlena & odeh, Tracy’s and Schilthuis. This paper compares estimation of reserve using dynamic simulation in MBAL software and predictive material balance method after history matching of both of this model. Results from this paper shows functionality of MBAL in terms of history matching and performance prediction. This paper objective is to set up the basic reservoir model, various models and algorithms for each technique are presented and validated with the case studies. Field data collected related to PVT analysis, Production and well data for quality check based on determining inconsistencies between data and physical reality with the help of correlations. Further this paper shows history matching to match original oil in place and aquifer size. In the end conclusion obtained from different plots between various parameters reflect the result in history match data, simulation result and Future performance of the reservoir system and observation of these results represent similar simulation and future prediction plots result.

Approaches to increasing well productivity in the development of the Bovanenkovo oil and gas condensate field

A large number of gas and gas condensate fields are located in the West Siberian mega-province and, to increase gas and gas condensate production levels, deposits located on the Yamal Peninsula should be introduced into development. Deposits of the Yamal Peninsula are complex-built deposits, Neocomian and Jurassic deposits have abnormally high reservoir pressure with a reservoir temperature of more than 100 ° C. The Bovanenkovo oil and gas condensate field is the largest in terms of gas reserves in the Yamal Peninsula; on this example, in this article we will study the issues of restoring the reservoir properties of reservoir rocks and increasing the flow of hydrocarbons. To select the optimal technology and composition for conducting water shutoff treatment, it is necessary to take into account the following factors: which reservoirs represent the reservoir, the percentage of water cut in the recoverable reserves, the tightness of the production string, the current flow rate of the well during operation at constant reservoir pressure, because each field needs an individual approach with a choice suitable water shuto-ff treatment technology.

Petrophysical interpretation and fluid substitution modelling of the upper shallow marine sandstone reservoirs in the Bredasdorp Basin, offshore South Africa

The fluid substitution method is used for predicting elastic properties of reservoir rocks and their dependence on pore fluid and porosity. This method makes it possible to predict changes in elastic response of a rock saturation with different fluids. This study focused on the Upper Shallow Marine sandstone reservoirs of five selected wells (MM1, MM2, MM3, MM4, and MM5) in the Bredasdorp Basin, offshore South Africa. The integration of petrophysics and rock physics (Gassmann fluid substitution) was applied to the upper shallow marine sandstone reservoirs for reservoir characterisation. The objective of the study was to calculate the volume of clay, porosity, water saturation, permeability, and hydrocarbon saturation, and the application of the Gassmann fluid substitution modelling to determine the effect of different pore fluids (brine, oil, and gas) on acoustic properties (compressional velocity, shear velocity, and density) using rock frame properties. The results showed average effective porosity ranging from 8.7% to 16.6%, indicating a fair to good reservoir quality. The average volume of clay, water saturation, and permeability values ranged from 8.6% to 22.3%, 18.9% to 41.6%, and 0.096–151.8 mD, respectively. The distribution of the petrophysical properties across the field was clearly defined with MM2 and MM3 revealing good porosity and MM1, MM4, and MM5 revealing fair porosity. Well MM4 revealed poor permeability, while MM3 revealed good permeability. The fluid substitution affected rock property significantly. The primary velocity, Vp, slightly decreased when brine was substituted with gas in wells MM1, MM2, MM3, and MM4. The shear velocity, Vs, remained unaffected in all the wells. This study demonstrated how integration of petrophysics and fluid substitution can help to understand the behaviour of rock properties in response to fluid saturation changes in the Bredasdorp Basin. The integration of these two disciplines increases the obtained results’ quality and reliability.

Petrophysical rock typing in unconventional shale plays: The Niobrara Formation case study

Production from organic-rich shale petroleum systems is extremely challenging due to the complex rock and flow characteristics. An accurate characterization of shale reservoir rock properties would positively impact hydrocarbon exploration and production planning. We integrate large-scale geologic components with small-scale petrophysical rock properties to categorize distinct rock types in low-porosity and low-permeability shales. We then use this workflow to distinguish three rock types in the reservoir interval of the Niobrara Shale in the Denver Basin of the United States: the Upper Chalks (A, B, and C Chalk), the Marls (A, B, and C Marl), and the Lower Chalks (D Chalk and Fort Hays Limestone). In our study area, we find that the Upper Chalk has better reservoir-rock quality, moderate source-rock potential, stiffer rocks, and a higher fraction of compliant micro- and nanopores. On the other hand, the Marls have moderate reservoir-rock quality and a higher source-rock potential. The Upper Chalks and the Marls should have major economic potential. The Lower Chalk has higher porosity and a higher fraction of micro- and nanopores; however, it exhibits poor source-rock potential. The measured core data indicate large mineralogy, organic richness, and porosity heterogeneities throughout the Niobrara interval at all scales.

New models for prediction of reservoir rock properties in Biyad formation of Kharir oil field, Hadramout Governorate

Reservoir description is a process of describing various reservoir characteristics using all the available data. The nature of the description of reservoir properties is related to the availability of sample data and geologic complexity of reservoir. Reservoir characterization is needed for effective reservoir management studies. Reservoir rock properties can be estimated by several methods. Rock properties are determined by performing laboratory analyses on cores extracted from the reservoir. However, obtaining the properties from core analysis or well logging is time consuming and an expensive operation. For that, in this work, new models for estimating rock properties (porosity, permeability) are developed by adapting Artificial Neural network model (ANN). Models were successfully demonstrated for predicting reservoir rock properties (porosity and permeability) forBiyad formation of Kharir oil field. The models were tested against properties yielded from core laboratories using statistical error analysis. Result showed a great potential in predicting reservoir properties using artificial intelligence models.

Experimental investigation of the primary and secondary creep behaviour of shale gas reservoir rocks from deep sections of the Cooper Basin

This paper investigates the mechanical properties of shale gas reservoir rocks from deep sections of the Cooper Basin with a focus on the creep deformation at high stress and temperature conditions. Rock samples are collected from depths greater than 3000 m in Nappamerri Trough of the Cooper Basin and a series of deformation as well as creep tests were carried out using a triaxial apparatus under simulated reservoir pressure and temperature conditions. Creep tests were conducted at different axial stresses for different durations. The results of this study show that temperature and differential axial stress (a difference between axial stress and confining stress) have significant bearing on the shales' mechanical properties, including creep deformation behaviour. A number of models developed by different authors were used to analyse the experimental data (creep deformation). It has been found that none of these models can adequately describe the creep behaviour of shale gas reservoir rocks from deep sections of the Cooper Basin. In this study we have revised the power-law model and incorporated Arrhenius factor (equation) to account for temperature effect on creep behaviour of shale gas reservoir rocks. The revised power-law model is used to simulate wellbore deformation of the Roseneath, Barnett and Eagle-ford shales at the Cooper Basin temperature and pressure conditions. The results show that the Barnett exhibits little viscoelastic deformation over time while Eagle-ford exhibited twice and Roseneath 180% as much as its instantaneous elastic response over a 24 h period.

Screening and optimization of polymer flooding projects using artificial-neural-network (ANN) based proxies

Polymer flooding is one of the most broadly implemented chemical EOR processes due to its low injection cost and successes in oil production increments. This work develops artificial-neural-network based proxies by utilizing synthetic production histories generated from a high-fidelity numerical simulation model. Injection-pattern-based reservoir models are structured to establish the knowledgebase to train the proxies. A forward and an inverse-looking ANN models are structured in this study. The forward-looking expert system are employed as a forecasting and screening tool that is capable to predict time-based project responses. And the inverse-looking ANN predicts the project design schemes that fulfill the expected oil recoveries. The proxies are generalized considering reservoir rock and fluid properties and project design parameters. In this paper, we present results of extensive blind testing applications to confirm the validates of the proxy models. Afterwards, various applications of the expert systems are discussed. A project screening protocol that couples the expert system and particle swarm optimization (PSO) methodology is presented to maximize the polymer injection projects' net present value (NPV). Moreover, we propose a robust computational workflow that coupled utilize the inverse and forward-looking proxies to find various polymer injection schemes to fulfill the expected oil production profile, which effectively addresses the issue associated with the existence of non-unique solutions in the inverse design problems. The expert ANN systems and the associated project design workflows provide versatile approaches for the field engineers to obtain quick techno-economical assessments of polymer injection projects.

Integrated sedimentological and seismic reservoir characterization studies as inputs into a Lower Cretaceous reservoir geomodel, offshore Abu Dhabi

Abstract Reservoir characterization plays a fundamental part in the development and/or appraisal of any hydrocarbon field. Understanding and quantifying the characteristics and distribution of the reservoir rock properties is an evaluation step that needs to be performed before starting any reservoir model. An accurate description of the reservoir is vital to help appropriately manage and optimize oil recovery. From core to seismic scale, any relevant piece of information should be integrated in order to reduce uncertainties, and optimize understanding of the final flow behaviour and fluid distribution inside the reservoir. The goal of the final geomodel is to obtain consistent properties that are driven by the geological facies models (including depositional facies and diagenesis; reservoir rock types) and trended by the seismic information.

Fractal dimension, lacunarity and succolarity analyses on CT images of reservoir rocks for permeability prediction

An explicit relationship between seepage properties and microscopic structure of porous media is being sought for the development of oil and gas resources. An effective method to accurately characterize and quantify the microscopic structure of porous media is a key issue. Fractal geometry can take advantage of several physically-based parameters to analyze microstructures of reservoir rocks. In this study, three fractal structural parameters, fractal dimension, lacunarity and succolarity, were employed to characterize scale-invariant complexity, heterogeneity, and anisotropy of rock microstructures, respectively. Twelve three-dimensional digital cores of sandstone reservoir rocks were used to evaluate permeability in terms of fractal dimension, lacunarity and succolarity. The parameters were utilized to quantitatively characterize differences in core micro-structure and predict their effects on permeability. Due to the confounding influence of porosity, the fractal dimension was not an accurate predictor of the variation in permeability on its own. Instead, the results reveal that lacunarity and succolarity were better able to predict differences in structure and permeability. Succolarity, in particular, showed an exponential relationship with permeability, yielding a coefficient of determination of 0.940. Using a combination of fractal structural parameters in the place of pore-size distribution, can provide a better explanation of the relationship between fluid flow, and the heterogeneous structure and anisotropic physical properties of reservoir rocks.

О ПРОДУКТИВНОСТИ И ПЕТРОФИЗИЧЕСКИХ ХАРАКТЕРИСТИКАХ КОЛЛЕКТОРОВ СЕВЕРНОЙ ЧАСТИ БАКИНСКОГО АРХИПЕЛАГА


 
 
 In the article was showed complex results of petro physical testing sample of rocks from taken digging prospecting-development wells which are widen productive unit sediments of the northern part of the Baku arxipelago. An average values of granulometric composition of rocks of productive unit the above areas by the section have been recount. The matter dependence of permeability from porosity and porosity from depth was solved. The research showed that the same named and the same age rocks physical property change at the result of geological- physical process and getting different prices. The reservoir properties of rocks of productive unit have been learned. The physical properties of rocks of productive unit have been shown in the table. The reservoir properties of different type of rocks which take part in the geological structure of oil and gas bearing areas and their spreading conformity to natural laws are shown in the table.Dependence between physical parameters for the individual kinds of rocks, dependence between physical properties and material structures are established.
 
 

Investigations of heat extraction for water and CO2 flow based on the rough-walled discrete fracture network

The Enhanced Geothermal Systems (EGS) has been developed to enhance geothermal energy extraction efficiency from geothermal reservoirs by generating effective fracture network. The fracture effective network that are comprised by rough-walled fractures can provide a more realistic reflection of natural reservoir conditions. This study focuses on the construction of a rough-walled discrete fracture model to simulate mass and heat transfer in a geothermal reservoir by using water and CO2 as the working fluid. The thermal-hydraulic-mechanical (THM) coupling process was integrated into the rough-walled discrete fracture network model. The heat mining processes with two working fluids (water and CO2) were simulated with the parallel-plate and rough-walled discrete facture network models. The influences of the parallel and rough-walled discrete fracture network models on flow behaviours, heat transfer and corresponding mechanical responses for water and CO2 were presented and analysed. What’s more, the heat extraction efficiency based on the combination of rough-walled discrete fracture network and the THM method were calculated and analysed in details. The influences of pressure, temperature, fluids and reservoir rock properties on heat extraction rates were also considered.It is found that CO2 leads to faster pressure changes compared with water in both parallel-plate and rough-walled discrete fracture network models. The influences of the pressure and temperature distributions on the permeability and normal stress were also evaluated, which contribute to the investigation of the deforming mechanisms of the rock matrix and fractures. In addition, there are certain differences in the heat production rate between the parallel-plate and rough-walled discrete fracture networks, which reflects that the rough-walled discrete fracture network used in this study has a better conductivity. It is also found that water can be a more efficient working fluid for heat extraction from geothermal reservoirs compared with CO2 during certain production durations in this study. The results of this study present that the rough-walled discrete network model has a great significance in the simulation of the real conditions and processes in geothermal reservoirs during the heat mining process.

The critical factors for permeability-formation factor relation in reservoir rocks: Pore-throat ratio, tortuosity and connectivity

The hydraulic properties of reservoir rocks have a directly impact on the flow path of exchange fluid in geothermal and oil reservoir systems. Estimation of hydraulic properties by means of electrical measurement is convenient and nondestructive in these reservoir systems. The mechanism beneath which the pore structure affects electrical and hydraulic flow in porous media is not yet fully understood. In this study, we present a new permeability-formation factor relation based on pore-throat size model and fractal geometry theory. Furthermore, an updated model accounting for the effect of tortuosity and connectivity is applied to characterize the permeability of porous media. The experimental results show that the pore-throat ratio cannot fully describe the relationship between the permeability and the formation factor without considering tortuosity and connectivity. The combined model including pore-throat ratio, tortuosity and connectivity is further proposed to exactly estimate the influence of complex pore structure on the transport behavior associated with electrical parameters. The result also indicates that pore-throat ratio, tortuosity, and connectivity are the three key factors determining hydraulic properties in porous media. This means the estimation of electrical conductivity changes with permeability that depends on accurate characteristic of micro-structural properties of reservoir rocks.

Lithofacial models of productive deposits of the Moshakov formation within the southwesten part of the Siberian platform

Система комплексной поддержки и сопровождения научного журнала Elpub позволяет запустить двуязычный сайт журнала со встроенной системой электронной редакции в соответствии с лучшими издательскими практиками, а так же предусматривает техническую и методическую поддержку со стороны специалистов НЭИКОН.

ПЕТРОФІЗИЧНІ МОДЕЛІ ТЕРИГЕННИХ КОЛЕКТОРІВ КАМ’ЯНОВУГІЛЬНИХ ВІДКЛАДІВ ЦЕНТРАЛЬНОЇ ЧАСТИНИ ДНІПРОВСЬКО-ДОНЕЦЬКОЇ ЗАПАДИНИ

The purpose of the work was to construct petrophysical models of reservoir rocks of different rank: typical and unified. Typical models describe connections between the parameters of individual rocks lithotypes occurring in definite geological conditions and serving as the basis for the development of petrophysical classification of reservoir rocks in the oil geology. The principle of unification provides for creation of the models structure for different reservoir lithotypes both in the geological section and in the area. We have studied petrophysical properties of reservoir rocks of Carboniferous deposits in the central part of the Dnieper-Donets depression. Petrophysical properties of rocks in conditions close to the formational ones and relations between them were studied on a number of samples formed by the core samples of different age. Main geological factors that have an influence on reservoir properties of rocks were taken into consideration. While constructing and analysing of petrophysical models we have used a probable-statistic approach with the use of the correlative-regressive analysis. Result of the work is contained in typical petrophysical models for individual areas and in unified models obtained on consolidated samples for Lower Carboniferous deposits of this region. Characteristic features in variations of petrophysical properties of reservoir rocks of Carboniferous deposits and their models have been ascertained. A conclusion has been made that multidimensional models, in which the depth of occurrence of deposits is one of the parameters that are necessary to consider while constructing petrophysical models, are the most informative for determination of petrophysical properties of the studied deposits, and the models obtained by us are known to be a petrophysical basis for quantitative interpretation of data from geophysical studies in the boreholes of the given region.

The Investigation of Permeability Calculation Using Digital Core Simulation Technology

Digital core simulation technology, as an emerging numerical simulation method, has gradually come to play a significant role in the study of petrophysical properties. By using this numerical simulation method, the influence of micro factors on seepage properties of reservoir rock is taken into consideration, making up the shortcomings of the traditional physical experiment. Three-dimensional core images are reconstructed by a computed tomography scanning technique. Different sizes of the sub-region were simulated by three methods including the direct computation of Navier-Stokes equations, the simulation of the pore network model, and the lattice Boltzmann method. The permeability computed by each simulation was compared. After comparison between these three methods, the results of the direct computation method based on Navier-Stokes equations were found to be higher than the other two methods. The pore network model simulation has an obvious advantage on the computation speed and the simulation area. The lattice Boltzmann method shows the low efficiency due to the time-consuming process. At last, the permeability calculated by the three methods is matched by the Kozeny-Carman equation. A more accurate formula can be obtained by a series of numerical simulations, which can be applied to marco-scale simulation.