Pore Space Of Rocks Research Articles

Improved methodology development for assessing the reservoir collector properties by the quantitative reservoir characterization tools

The object of research in the paper is the process of fluid transfer through the pore space of the reservoir rock. In this paper, using an expert method, the shortcomings of the Ukrainian methodology for assessing the reservoir properties of the reservoir were highlighted. In particular, the sources of uncertainty accumulation in determining the absolute values of the reservoir's filtration parameters have been identified. The existing problem is that the algorithms of actions, which are the basis of the Ukrainian method of assessing reservoir properties, introduce a significant degree of uncertainty into the assessment results. In order to reduce uncertainty, the introduction of the concept of a representative elemental volume is considered when conducting laboratory research and the construction of a three-dimensional digital model of this elementary volume. It is suggested to improve the Ukrainian method of assessing the collector properties of the deposit based on current Western research. It was established that the standard methods of assessing the reservoir properties of the deposit are a source of accumulation of uncertainty in the development of technological documentation for the development of the deposit. The work is aimed at the development of an improved methodology for assessing the collector properties of the deposit. It is proposed to add to the action algorithm the stage of determining the representative volume of the sample, building its three-dimensional model, and digitizing it. At the final stage, the connectivity of the pores inside the sample is determined using the Minkowski function to improve the quality of the project documentation for the development of deposits. Guidelines have been developed to improve standard methods for assessing the collector properties of the deposit. The use of an improved methodology for assessing the reservoir properties of the deposit leads to a significantly lower degree of uncertainty and helps to form a more reliable picture of the operation of the reservoir at the design stage of its development. The presented study will be useful for the engineering personnel of foreign contractor companies, as it justifies the need to collect additional core material and sets the quality criteria of the information obtained about the collector properties of the deposit.

Red Noise in Steady‐State Multiphase Flow in Porous Media

AbstractUnderstanding the interaction between competing fluids in the pore space of rocks is key for predicting subsurface flow and trapping, such as with CO2 in a saline aquifer. These processes occur over a large span of timescales (from seconds to thousands of years), and length scales (from microns to kilometers). Understanding the link between these temporal and spatial scales will enable us to interpolate between observations made at different resolutions. In this work we explore the temporal scales present during macroscopically steady‐state multiphase flow in a porous carbonate rock using differential pressure measurements acquired over a period of 60 min. Nitrogen and brine were injected simultaneously into a sample 5 mm in diameter and 21 mm in length. We observe a cascade of timescales in the pressure differential that is, a continuous range of frequencies, with lower frequencies having greater amplitudes. We demonstrate a scaling of the spectral density with frequency of S ∼ 1/f2, or red noise, to describe the dynamics. This scaling is independent of the flow rate of the fluids or the fraction of the flow taken by water. This red, or Brownian, noise indicates a stochastic process where pressure fluctuations are seen throughout the pore space, resulting in intermittent filling of pores over a wide range of time‐scales, from seconds to minutes in these experiments. The presence of red noise suggests self‐organized critically, with no characteristic time or length scale.

Evaluation of void space of complicated potentially oil-bearing carbonate formation using X-ray tomography and electron microscopy methods

The Vereiskiy reservoir (Perm Region, Russia) is one of the complicated oil-bearing carbonate formations. It consists of interbedded carbonates and clayey rocks with low interbedded thickness (3–6 m), which makes its development unprofitable. But this reservoir is promising for oil production in the case of application of new technologies (especially proppant hydraulic fracturing method). The different methods of investigation (core description, geophysical, X-ray tomography, electron microscopy, well logging, difference parameters, well test, Warren-Root model, etc.) are used for description its rock pore space. The four lithotypes are distinguished, and their unhomogeneous structure is found out. The presence of large number of intergranular pores, orienting along definition direction, weakly leaching voids, decompaction zones, local thickening of microcracks are the real prerequisite factors promoting the formation of channels for active oil migration under the influence of the factors of hydraulic fracturing technology.

THE INFLUENCE OF ALCOHOL TYPE AND CONCENTRATION ON THE PHASE BEHAVIOR AND INTERFACIAL TENSION IN OIL-SURFACTANTCOSURFACTANT-BRINE MIXTURE SYSTEM

The number of mechanism is limited for reducing the entrapment of oil in the pore space of reservoir rock and for mobilizing that residual which remains entrapped, thereby improving the microscopic displacement efficiency of a petroleum recovery process. After primary recovery by flow powered by the energy stored in the compressed fluids of reservoir, and secondary recovery by injection-pump driven water flooding, residual oil is trapped by the capillary pressure developed by interfacial tension in curved menisci between oil and water in the pore space. Figure 1.1 illustrates the interplay of capillary and viscous forces in the water flooding process. Shown in the figure is water displacing oil. The important point is that residual oil is trapped in the pore space by interfacial tension. To improve micros- copic displacement efficiency is to reduce interfacial tension between oil and water. Surfactant is surface active agent chemical that has two types of properties; lypofob (like water) and hydrofob (like oil). The value of interfacial tension between oil and water is high, when surfactant is dissolved into water and contacts with oil, so that surfactant is not only soluble in the water, but also it is soluble in the oil. By addition of surfactant into the water and contact with oil can result in interfacial tension between oil and water from high (more less 20 - 30 dyne/cm) to lower interfacial tension (10-2 dyne/cm). To change the lower interfacial tension to the lowest interfacial tension conditions (10-4dyne/cm), cosurfactant in oil-surfactant-brine mixture is used. Alcohols are widely used in micellar surfactant systems for enhanced petroleum recovery and are variously called cosurfactant or cosolvent. In general, alcohols modify the physico- chemical properties in ways that are important to the design of surfactant-based process for improving petroleum recovery. This research is focused on alcohol effects on oil-surfactant-brine phase behavior and interfacial tension of oil-surfactant-brine system.

Evolution of Bentheimer Sandstone Wettability During Cyclic scCO2‐Brine Injections

AbstractGeologic sequestration in sedimentary formations has been identified as a potential technology to prevent climate‐change inducing carbon dioxide (CO2) from being emitted to the atmosphere. To achieve safe and effective storage underground, accurate understanding, and predictions of supercritical CO2 (scCO2) behavior in subsurface rock formations is required; including quantifying how much scCO2 is trapped within pore spaces by capillarity (vs. how much remains mobile), and constraining the occurrence of physio‐chemical reactions between scCO2 and the mineral matrix. Experiments where multiple cycles of scCO2 and brine are injected into rock samples have produced conflicting results regarding the consistency of trapping as cycles progress; likely due to differences in mineral content, pressure‐temperature conditions, aqueous chemistry parameters, and experimental setups. We present a new set of experiments, replicating the conditions of a previous study, but with a new experimental design, apparatus, and timeline. We confirm previous results that demonstrated shifts in injection pressure and scCO2 trapping behavior over multiple injection cycles, and we conduct additional analyses to discern the fluid‐fluid macroscopic contact angle, interface mean and Gaussian curvatures, scCO2 interfacial area, and topology of trapped scCO2 ganglia. We also performed lattice‐Boltzmann simulations approximating experimental conditions where solid wettability was systematically altered over multiple injections cycles; trends in scCO2 ganglia characteristics compare well between experiment and simulation. The results indicate that this system undergoes a transition to a “patchy” mixed‐wet state, and we observe that this wettability alteration renders scCO2 more stable in the rock pore space, increasing capillary trapping over four injection cycles.

Can fluid-substitution models continue to ignore the complex physicochemical properties of crude oil?

The mechanical nature of fluid-substitution models has always been recognized as a major cause of their limited predictive power. For instance, saturants are typically treated as simple fluids characterized only by their densities, viscosities, and moduli of elasticity; their chemistry is just ignored, even when that fluid is crude oil. However, crude oil is a complex mixture of several thousand organic compounds characterized by a variety of molecular weights, polarities, and polarizabilities, and the response of its rheological behavior to acoustic wave propagation is difficult to predict, especially when it resides in the pore space of rocks. We have performed ultrasonic-velocity measurements on carbonate core plugs saturated with a brine and with a light crude oil that are mechanically similar (i.e., having comparable densities, viscosities, and moduli of elasticity) and that show a significant and consistent excess of hardening when the saturant is oil. Dispersion and wettability are excluded as explanations for the data. We hypothesize that asphaltene aggregation and adsorption as well as paraffin-wax crystallization (and possibly volumetric expansion) combine to cause crude oil to exhibit a dilatant-like behavior within the pore space of carbonates at ultrasonic frequencies. In general, the observed effect would be similar to the hardening of ooblek at high deformation rates. This hypothesis could be tested in the future by an adequate combination of high-resolution imaging and microfluidic setups. This and similar studies would be beneficial in developing physical fluid-substitution models with a more consistent predictive power.

Relationship Between Zeta Potential and Wettability in Porous Media: Insights From a Simple Bundle of Capillary Tubes Model

Hypothesis & MotivationExperimental data suggest a relationship between the macroscopic zeta potential measured on intact rock samples and the sample wettability. However, there is no pore-scale model to quantify this relationship. MethodsWe consider the simplest representation of a rock pore space: a bundle of capillary tubes of varying size. Equations describing mass and charge transfer through a single capillary are derived and the macroscopic zeta potential and wettability determined by integrating over capillaries. Model predictions are tested against measured data yielding a good match. FindingsMixed- and oil-wet models return a macro-scale zeta potential that is a combination of the micro-scale zeta potential of mineral-brine and oil-brine interfaces and the relationship between macro-scale zeta potential and water saturation exhibits hysteresis. The model predicts a similar relationship between zeta potential and wettability to that observed in experimental data but does not provide a perfect match. Fitting the model to experimental data allows the oil-brine zeta potential to be estimated at conditions where it cannot be measured directly. Results suggest that positive values of the oil-brine zeta potential may be more common than previously thought with implications for surface complexation models and the design of controlled salinity waterflooding of oil reservoirs.

Effects of Fracture Characteristics on Spontaneous Imbibition in a Tight Reservoir

Horizontal well fracturing technology is widely used in the development of shale gas resources. After the fracturing operations, natural and artificial fractures exist in the reservoir at the same time, which has significant effects on spontaneous imbibition to increase shale gas production. Based on nuclear magnetic resonance technology, this work studies the spontaneous imbibition property of fractured shale, including artificial and natural fractures, surface cemented minerals, boundary conditions, etc. The results show that the relaxation time spectra reflect the characteristics of water and gas migration in the rock pore space. The micropores and the small pores are the main storage space for water in shale. After water imbibition starts, the imbibition volume is roughly proportional to the square root of time. Through the comparative experiments on artificial fractures, natural fractures, and seamless cores, it is found that the existence of fractures can significantly promote water imbibition, and the imbibition speed of artificial fractured cores is faster than those of others. Because of the existence of artificial and natural fractures, the number of pores for gas discharge increases, and the imbibed volume is slightly more. When the cemented minerals such as quartzite and calcite are attached to the core surface, they have poor water sensitivity and block some of the pores, thus resulting in a slower imbibition speed. Different boundary conditions will not only affect the contact area between the core and water but also influence the types of imbibition, which changes the water flow path and imbibition speed. This study provides an important insight into spontaneous imbibition in gas shale after the fracturing operations.

ESTIMATION OF WETTABILITY OF TERRIGENOUS ROCK SAMPLES BASED ON MEASUREMENTS OF DIFFUSION-ADSORPTION ACTIVITY

The wettability of rocks has a significant impact on their properties, both reservoir and physical - capillary pressure, relative phase permeability, residual oil saturation. The dependence of these parameters on wettability is explained by the structural-textural and surface-molecular complexity of the systems under study, which makes this characteristic particularly important when studying the distribution of oil and water by reservoir thickness, the process of fluid movement in the reservoir and oil displacement, as well as when interpreting geophysical research data. The determination of the wettability of the pore space is based on the study of the adsorption properties of fluid molecules interacting with the rock surface. Known methods for estimating the wettability of the surface of the pore space of rocks, based on determining the value of the wetting edge angle, as well as determining the spin-lattice relaxation time by nuclear magnetic relaxation, are not widely used in practice. The most common methods for assessing wettability are dynamic methods based on capillary displacement of water from a water-saturated sample by a hydrocarbon liquid and further displacement by water. However, dynamic methods have certain disadvantages, such as the deformation of rock samples during experiments - the formation of cracks, chips, as well as a large time range of studies. In this paper, we propose a method for estimating wettability using the dependence of the diffusion-adsorption activity on the coefficient of relative clay content of rocks based on measurements of diffusion-adsorption activity of rock samples, excluding the limitations of dynamic methods. The aim of the work is to test the proposed method for assessing the wettability of the surface of the pore space on samples of a terrigenous reservoir, namely, to identify zones of various types of wettability and to determine the boundary values of the diffusion-adsorption activity corresponding to certain areas. The obtained results can be offered for use by specialists working in the areas of hydrodynamic reservoir modeling, reserve calculation, and methods for increasing oil recovery.

On the Microstructural Orientation of the Pore Space of Rocks: SEM Data

On the Microstructural Orientation of the Pore Space of Rocks: SEM Data

Laboratory studies of oil-displacing characteristics of emulsion solutions in the pore space of reservoir rocks

Chemical enhanced oil recovery methods are widely used in field development. One of the methods for leveling injectivity is emulsion-based technologies. The mechanism of this technology is to create an increased filtration resistance of the most depleted reservoir intervals. To establish the actual oil-displacing characteristics of the emulsifier grades accepted for testing in the pore space of oil-containing reservoir rocks, a set of laboratory filtration studies was carried out on high-permeability core models at the AS12 horizon of the Nizhne-Sortymskoye oil field.Processing laboratory data after filtration of ready-to-use emulsions through core samples gives an increase in the oil displacement coefficient by water from 1.31 to 10.79 %. When constructing their correlation dependence, it is possible to identify the range of the final dynamic viscosity (from 5 to 9 mPa∙s) of the compositions of the emulsion-based technology, which is optimal for the most effective application on groups of AS formation.Based on the laboratory studies of rocks, it was established that carrying out geological and technical measures using the emulsifier Neftenol-NZ, which has proven itself in high efficiency from well treatments, will give a large volume of additional oil production, in comparison with the currently emulsifier Sinol-EM.

Further Insights into the Performance of Silylated Polyacrylamide-Based Relative Permeability Modifiers in Carbonate Reservoirs and Influencing Factors.

We have previously used surface chemistry analysis techniques to optimize the functionalization of carbonate rocks with a silylated polyacrylamide-based relative permeability modifier (RPM). The RPM is expected to selectively reduce the permeability to water in a hydrocarbon reservoir setting, resulting in a reduction in the amount of produced water while maintaining the production of oil/gas. This study will focus on using core flooding techniques with brine/crude oil under reservoir conditions (i.e., 1500 psi pore pressure and 60 °C temperature) to understand the impact of a silylated polyacrylamide-based RPM on the fluid transport properties in carbonate rocks. The effects of RPM concentration, brine salinity, rock permeability, and pore structure on permeability characteristics were studied. Scanning electron microscopy (SEM) combined with energy dispersive spectroscopy (EDX) provided visual images of the polymer adsorbed onto the rock surfaces and confirmed the attachment of the polymer on the surface of the rock pore space after treatment. The relative percentage of Si increased from 1.65 to 13.55%, and the relative percentage of N increased to 4.54%. Core flooding showed that increasing the PAM-co-AA (poly acrylamide-co-acrylic acid partial sodium salt) concentration resulted in residual resistance factors for oil (RRFoil) and brine (RRFbrine) that were greater than 1. However, there was a modest decrease in the disproportionate permeability reduction (DRP) ratio (RRFbrine/RRFoil) from 1.75 to 1.60 when the polymer concentration was increased from 0.05 to 0.1 wt %. Furthermore, the RRFbrine values decreased slightly from 120 to 62 with increasing salinity (i.e., 1–10% NaCl) because of electrostatic shielding caused by charged ions in brine and the RPM. The cross-over points of relative permeability in these four samples shifted to the right because of the larger decrease in relative water permeability compared with relative oil permeability. End-point relative permeability to water in sample C-5 decreased by 80%, showing a reduction greater than that in the sample C-2 (i.e., 74%). Kr curves indicated a stronger formation damage in sample C-1, C-2, and C-4 than in sample C-5. Rock samples with a higher initial permeability exhibited a higher RRFbrine to RRFoil ratio (i.e., 3.05) under similar test conditions. This can be attributed to a larger pore radius, which was verified by nuclear magnetic resonance (NMR) measurements. Furthermore, a detailed mechanism has been proposed to understand the effects of the RPM on fluid transport in porous carbonate cores. In this study, SEM–EDX and NMR measurements combined with core flooding tests provide insights into the performance of silylated polyacrylamide-based RPMs and benefit its future implementation in carbonate reservoirs.

Characteristics of Hydration Damage and Its Influence on Permeability of Lamellar Shale Oil Reservoirs in Ordos Basin

The continental shale oil reservoir has low permeability, high clay content, rich lamellar structure, and strong heterogeneity, which makes the reservoir vulnerable to hydration damage. In order to study characteristics of hydration damage and its influence on permeability of lamellar shale oil reservoirs, a series of experiments such as high-pressure mercury injection, steady gas permeability, rock thin section identification, and scanning electron microscope were carried out with the downhole core in Ordos Basin as the experimental object. The effects of water and water-based drilling fluid on pore size distribution, permeability, and rock microstructure were analyzed. Results show that the pore size of the reservoir is mainly nanoscale, and the pore size of shale changes most dramatically in the stage of hydration for 12-24 hours, while that of tuff changes most dramatically in 24-48 hours. The permeability increases rapidly with hydration time and then tends to be stable, among which the permeability of samples with lamellar structure in the direction parallel to the lamellar structure is most easily affected by hydration and changes fastest. Hydration leads to the formation of new pores, new fractures, and the expansion of existing fractures in rocks, especially in the strata containing large amounts of terrigenous clastic, lamellar structure, and pyrite. The new seepage channel increases the permeability of rock, and the soil powder and plugging particles in drilling fluid are easy to form protective mud cake in these places. These protective mud cakes not only change the microstructure of rock but also inhibit the influence of hydration on the pore space and permeability of rock, which play an effective role in preventing the mineral shedding on the rock surface, reducing the increase of micropores and delaying hydration.

Исследование температурных условий образования органических отложений в продуктивном пласте при скважинной добыче парафинистой нефти

The paper presents the studies results of the temperature conditions for the formation of organic (asphalt-resin-paraffinic) deposits in the productive formation during the downhole production of paraffinic oil, including the results of experimental studies to assess the temperature of oil saturation with paraffin in the pore space of reservoir rocks. The studies were carried out in order to substantiate and develop a technology for preventing such deposits in the "reservoir - well" system. The results of filtration and rheological studies showed that for the same oil, the wax saturation temperature in the pore space of the reservoir rock could exceed the value of this parameter in the free volume. It was found that for the investigated solutions (models of highly paraffinic oils), the phase transition of paraffin from liquid to solid state, the formation of wax crystals in the pore space occured at a temperature 3-4° C higher than in the free volume. The results of tomographic studies of the core material, performed before and after filtration of a paraffin-containing solution through it with a decrease in temperature, showed that the open porosity of rock samples decreased on average four times due to the clogging of their pore space with paraffin. Based on the results of the filtration experiment and computed tomography, a digital core model was created, which allowed modeling the fluid flow in the pore space of the rock before and after the formation of paraffin deposits in it. The calculations results of the changes dynamics in the thermal field around the injection well confirmed the probability of cooling the bottomhole zone of the well to a temperature equal to the temperature of the onset of wax crystallization, as well as the probability of the cold water front advancing to neighboring production wells, which could cause a significant decrease in the productivity due to the formation of paraffin deposits in pore space of reservoir rocks. The research results are recommended to be taken into account when developing oil fields in conditions of possible formation of organic (asphalt-resin-paraffinic) deposits in the productive formation. This will make it possible to more reliably predict and effectively prevent its formation in the "reservoir - well" system.

Aromatic compounds in bitumoids of the Bazhenov Formation in the North of the Khantey hemiantheclise

The main features of the geochemistry of individual aromatic compounds (phenanthrenes, dibenzothiophenes, mono- and triaromatic steroids) in chloroform extracts (bitumoids) from the open (regular form and coarse-crushed (≥0.5 cm) samples) and closed (fine-crushed (0.25 mm) samples) pore space of the Bazhenov Formation have been determined. The differences in the aromatic compounds distribution of organic matter of the Bazhenov Formation in the North of the Khantey hemiantheclise (Surgut region, Khanty-Mansiysk Autonomous District, Western Siberia) are mainly related to its stage of thermal maturity which decreases in the south-west direction within the studying area. The most sensitive to maturity variations at the same catagenesis gradation are the parameters: CPI, Ts/Tm, 1/Ki ((n-C17 + n-C18)/(Pr + Ph)), MDR (4-MDBT/1-MDBT), DBTI ((2+3-MDBT)/DBT) and TASI (TAS I/(TAS I + TAS II)). Based on some indicators (PI, MPI, PP-1, MDR, DBTI etc.), it is possible to notice the decrease and equalization of its values in bitumoids from closed pores compared with those from open ones. It seems to be associated with the removal of the most transformed, light and migratory-capable part of bitumoids during their extraction from the open pore space of rocks.

Culture-Dependent and Amplicon Sequencing Approaches Reveal Diversity and Distribution of Black Fungi in Antarctic Cryptoendolithic Communities.

In the harshest environmental conditions of the Antarctic desert, normally incompatible with active life, microbes are adapted to exploit the cryptoendolithic habitat (i.e., pore spaces of rocks) and represent the predominant life-forms. In the rocky niche, microbes take advantage of the thermal buffering, physical stability, protection against UV radiation, excessive solar radiation, and water retention—of paramount importance in one of the driest environments on Earth. In this work, high-throughput sequencing and culture-dependent approaches have been combined, for the first time, to untangle the diversity and distribution of black fungi in the Antarctic cryptoendolithic microbial communities, hosting some of the most extreme-tolerant microorganisms. Rock samples were collected in a vast area, along an altitudinal gradient and opposite sun exposure—known to influence microbial diversity—with the aim to compare and integrate results gained with the two approaches. Among black fungi, Friedmanniomyces endolithicus was confirmed as the most abundant taxon. Despite the much stronger power of the high-throughput sequencing, several species were not retrieved with DNA sequencing and were detectable by cultivation only. We conclude that both culture-dependent and -independent analyses are needed for a complete overview of black fungi diversity. The reason why some species remain undetectable with molecular methods are speculated upon. The effect of environmental parameters such as sun exposure on relative abundance was clearer if based on the wider biodiversity detected with the molecular approach.

Experimental investigation of the geochemical and mineralogical interaction between CO2 and carbonate: Evaluation of CO2 sequestration in dolomite-calcite formations

Sequestration of CO2 in saline aquifers has become a renowned procedure owing to the availability of this type of reservoir. This study aims to identify the induced rock and fluid interactions during CO2 injection and their influence on the reservoir rock properties like porosity and permeability. A systematic study is required for further evaluation of these interaction effects. The experiments were collected from Iranian Asmari formations in Fars province with significant quantities of dolomite revealed by XRD analysis. The carbonate rock sample is considered for this study since most of the oil reservoirs in Iran are produced from carbonate Asmari formation.A series of core-flood experiments were carried out to assess the potential of dolomites to buffer brine and further promote mineral precipitation over time. Carbonate samples were exposed to CO2 for 2 weeks and 4 weeks. The dissolution and precipitation of minerals were investigated using CBCT to determine the impact of these processes on rock properties. The result of 4-weeks experiments showed that the reaction with CO2 causes salt precipitation which is observed in FE-SEM and EDS. The ICP and IC analysis tests showed that long-term CO2 reaction also creates a significant CO2 drying-out effect and salt (NaCl) crystallization in the aquifer's rock pore space by altering the pore structure. Such mineralogical alterations considerably affect the saline aquifer properties, producing noteworthy outcomes in the sequestration process. For example, the core permeability (C2) at 1 ml/s CO2 injection rate and confining pressure of 22 MPa decreased considerably from 51.8 to 15.06 mD with decrease in porosity from 22.90 to 15.56 using imaging technology (dental X-ray CT). Furthermore, CO2 storage capacity of both core samples was measured for a brine system with a salt concentration of 150,000 ppm.

A quantitative interpretation of the saturation exponent in Archie\u2019s equations

Saturation exponent is an important parameter in Archie’s equations; however, there has been no well-accepted physical interpretation for the saturation exponent. We have theoretically derived Archie’s equations from the Maxwell–Wagner theory on the assumption of homogeneous fluid distribution in the pore space of clay-free porous rocks. Further theoretical derivations showed that the saturation exponent is in essence the cementation exponent for the water–air mixture and is quantitatively and explicitly related to the aspect ratio of the air bubbles in the pores. The results have provided a theoretical backup for the empirically obtained Archie’s equations and have offered a more physical and quantitative understanding of the saturation exponent.

Laboratory studies of oil-washing characteristics of surfactants in the pore space of reservoir rocks

When developing hard-to-recover reserves of oil fields, methods of enhanced oil recovery, used from chemical ones, are massively used. To establish the actual oil-washing characteristics of surfactant grades accepted for testing in the pore space of oil-containing reservoir rocks, a set of laboratory studies was carried out, including the study of molecular-surface properties upon contact of oil from the BS10formation of the West Surgutskoye field and model water types with the addition of surfactants of various concentrations, as well as filtration tests of surfactant technology compositions on core models of the VK1reservoir of the Rogozhnikovskoye oil field. On the basis of the performed laboratory studies of rocks, it has been established that conducting pilot operations with the use of Neonol RHP-20 will lead to higher technological efficiency than from the currently used at the company's fields in the compositions of the technologies of physical and chemical EOR Neonol BS-1 and proposed for application of Neftenol VKS, Aldinol-50 and Betanol.

Groundwater Management in India: Problems and Perspectives

Groundwater, which occurs beneath the surface of the land, filling the pore spaces of rocks called aquifers, plays a great role in the human lives as it constitutes the major portion of the world’s drinking water. Groundwater is heavily relied upon for other domestic purposes, agriculture and industrial uses also. Indiscriminate and unplanned over-extraction and use of groundwater has led to groundwater depletion and pollution and the groundwater reserve all over is under an intense pressure. This paper highlights the evolution and recognition of right to water in India and in the international framework. It traces the evolution of statutes in relation to the control of groundwater resources, starting from the Colonial era, traversing through the latest legislative attempts initiated for the conservation of groundwater in India. In order to address the issues related to the use of groundwater and to comprehensively identify strategies for management of the same in the best way, there is a need for coordinated efforts by the stakeholders including the government, industries, and agriculturists and so on. Immediate and stringent actions are required to ensure sustainable utilisation of this resource so that it can be preserved for the generations to come. The paper concludes by giving suggestions and recommendation for the enhancement of the legal regime for the effective preservation and maximum utilisation of the groundwater resources.