Maintain Reservoir Pressure Research Articles

Impact of hydrogen solubility on depleted gas field's caprock: an application for underground hydrogen storage

Depleted gas fields are considered a low-risk location for underground hydrogen storage purposes to balance seasonal fluctuations in hydrogen supply and demand. The objective of this study was to identify any significant risk of hydrogen leakages stored in depleted gas fields. The capability of the storage area in terms of sealing efficiency varies with parameters such as rate of diffusion, solubility, thickness and capillary threshold pressure of the caprock. The most common caprock are shales, which contain organic material. The solubility of hydrogen into organic material could change the petrophysical properties of the rock, such as porosity and permeability. Any changes in these petrophysical characteristics can reduce the capillary threshold pressure thus reducing the caprock efficiency for the safe storage of hydrogen. There is about 20% of the remaining gas volume in the depleted gas field, which helps to prevent brine from entering the production streamlines and maintain reservoir pressure. The characteristic data of hydrogen at different high pressures and temperatures have been evaluated and imported into the simple finite element model using the Python programming language. Most of the parameters that influence reducing the strength of the caprock are identified. Crucial parameters are the rate of diffusion, the solubility of hydrogen in kerogen, geomechanical deformation, threshold capillary pressure, long period of injection and withdrawing of hydrogen. The model shows that the native gas production with hydrogen is low due to significant density variation and mobility ratio between methane and hydrogen. Finally, a wide range of parameters and reservoir conditions has been considered for minimising the potential risks of possible leakages.

Assessment of CO2 flooding as enhanced oil recovery

This article discusses evaluating CO2 injection as an enhanced oil recovery method. Carbon dioxide injection is a secondary and tertiary enhanced oil recovery method and is used in the final stage of development. Carbon dioxide mixes well with oil and can dissolve heavy components. Also, CO2 maintains reservoir pressure, which prevents the flow rate from dropping. In order for carbon dioxide and oil to mix, it must be brought to a critical state by increasing the temperature and pressure. After reaching the required conditions, both substances are fully compatible. The result of this combination is a medium that can easily seep through a porous medium. In fact, gas injection would be appropriate to use in a carbonate reservoir, and in our country and all over the world there are many oil fields that are located in carbonate rock. This work is based on data on a field located in the Krasnoyarsk region, which is part of the Angara fold zones. The field itself is represented mainly by carbonate reservoirs. Also, application of this method for Kazakhstan oilfield will be considered, using an example Zhetybay oilfield.

Geological criteria and methods to increase condensate extraction at the late stage of gas condensate deposits' development

Formulation of the problem. Ukraine is one of the oldest oil and gas producing countries in the world. Maximum volumes of gas (68 billion m3 per year) were extracted in 1975-1978. After this period, production began to decline. About 18 billion m3 of gas was extracted in 2019 in Ukraine. The question arose of studying ways to increase the annual production of gas and condensate from old fields. The total residual reserves of deposits in late operation are estimated at more than 200 billion m3 and are classified as difficult to extract. Review of previous publications and studies. Scientific publications consider technologies and ways to increase hydrocarbon extraction. Bikman E. S showed the dynamics of the specific condensate content in gas formation depending on the formation pressure at the fields of Ukraine. Reducing pressure during the development of gas condensate deposits with a high initial content of condensate in the formation gas to the condensation start pressure leads to "avalanche" condensation of liquid hydrocarbons.This causes the loss of heavy hydrocarbons in the depletion process of this type of field. There are two ways to increase hydrocarbon recovery of gas condensate fields:to use methods to maintain reservoir pressure in the initial stages of their development, and to use secondary methods of condensate extraction that fell in the reservoir at the later stages. Object of research: gas-condensate fields with significant volumes of condensate that have fallen into them, and the possibility of its extraction at a later stage of development. Results. In this study, the authors identified systems of gas-condensate fields development to ensure the extraction of condensate in the formation. The article considers five theoretically possible options to improve the energy efficiency of gas condensate fields. For practical use, two methods are recommended: gas bypass from deposits with high pressure and low condensate content in deposits with lower formation pressure and high condensate content; continued depletion of deposits at low formation pressures less than the maximum condensation pressure. The organization of gas bypass in order to increase the extraction of condensate from depleted formations is possible under the condition of low condensate content and higher formation pressure in the deposit from which it is planned to carry out gas bypass. The transfer of gas from a deposit with higher values of the average condensation factor to a deposit with lower values is inefficient. The authors apply a mathematical device which can be used to forecast development of two deposits in the mode of gas bypass with definition of alignment time of formation pressures in their depletion. It is established that the use of the cycling process at the late stage of gas-condensate fields operation at formation pressures less than the maximum condensation pressure (P reservoir <Pmax) is impractical even in deposits with high condensate content. Thus, such deposits should continue to be developed for depletion. We analyzed the efficiency of gas condensate deposits development on the example of separate deposits of Ukraine.

ГИДРОГЕОЛОГИЧЕСКАЯ ХАРАКТЕРИСТИКА ПЛАСТОВЫХ ВОД КАСПИЙСКИХ МОРСКИХ МЕСТОРОЖДЕНИЙ

Hydrogeological conditions of reservoir waters of oil and gas fields in the northern water area of the Caspian Sea characterize the geological features of the structure of the Northern Caspian shelf, as well as the thermodynamic parameters of the exploitation of productive deposits, production and transportation of oil and gas. Reservoir waters contain water-soluble gases. According to the size of mineralization, the ratio of the main components of the salt composition, as well as the presence of iodine and bromine, reservoir waters can be attributed to a relatively "young" genetic age, subject to secondary geochemical processes of changing the salt composition in interaction with "secondary" migrated hydrocarbons. The physical and chemical properties of reservoir waters are determined by PVT analysis technologies. Hydrogeological and geochemical studies of compatibility with reservoir waters of marine waters injected to maintain reservoir pressures (PPD) during the development of offshore fields in order to increase the oil recovery coefficient (KIN) indicate the absence of colmating secondary sedimentation in mixtures of natural and man-made waters.

Предотвращение осложнений при использовании несовместимых вод в системе поддержания пластового давления

A pressing task in the operation of a reservoir pressure maintenance system is the prediction and monitoring of the state of the internal surface of pipelines and the total amount of sediment. The article examines the mechanism of formation of salts of carbonate and sulphate groups in the process of mixing reservoir and artesian waters, which are incompatible, when used in the system for maintaining reservoir pressure. The mechanism of formation of iron compounds when mixing waters with different pH values is considered. The effect of bacteriological contamination of the production media on the increase in the amount of iron sulfides in the production media, as well as the development of equipment biocorrosion is shown. The features of biodegradation of the field pipeline system under conditions of low reservoir temperatures are considered. The most promising methods of dealing with scaling and biocorrosion under conditions of low temperatures of field fluids are noted.

Development of devices for implementation pulse nonstationary waterflooding

To further improve the efficiency of the non-stationary flooding (acceleration of capillary impregnation oil closed pores) at the bottom of injection wells installed devices, creating pulses in the pumped liquid, with a packer. The article deals with a device designed for this purpose. A mathematical model of the device and output expressions to define the basic operating parameters of output. For comparison of theoretical calculations show the results of bench testing device. In view of previous research, the authors of substantiated the effectiveness of such devices for the nonstationary flooding in the system to maintain reservoir pressure. The preliminary positive data on fishing the use of these devices in the fields of NC «Rosneft» in 2015-2016.

Experimental investigations of rock-fluid interactions in low salinity water injection for enhanced oil recovery in Shaly carbonate oil reservoirs

ABSTRACT Water flooding has regularly been acknowledged as a promising method to maintain reservoir pressure during oil production. The foremost challenge that comes with this approach is the increase in scale potential due to the incompatibility between the injected water and the in-place water due to their diverse physical and chemical properties. In this paper, the thermodynamic conditions for the formation damage caused by the inorganic deposits, swelling of the clay minerals, and their migration through porous media was experimentally investigated, and then the effect of these deposits on the permeability of Shaly-carbonate core samples was investigated. Additionally, the effect of salinity of the injected water on the swelling and non-swelling clay minerals were investigated, and the critical salt concentration (CSC) of the injected water was experimentally and mathematically estimated. The results indicated that the deposition of calcium sulfate ions causes the highest damage factor (up to 60%) with the lowest pore volume (P.V.) of the injected water (7 P.V.), as mostly non-removable damage. Also, the CSC of the injected water reached to the swelling clay inorganics was higher than that for the non-swelling clay minerals. Eventually, the second type of CSCs of the injected waters containing the ions Na+, Na++Ca2+, and Ca2+ were experimentally obtained as 0.5, 0.05, and 0.01 and mathematically estimated as 0.35, 0.06, and 0.01, respectively.

Numerical simulation and laboratory experiments of CO2 sequestration and being as cushion gas in underground natural gas storage reservoirs

Underground natural gas storage reservoir is generally used to stabilize the natural gas supply to meet the high and low peak of gas consumption. In addition, in the case of depleted gas reservoirs, the leftover native gas or cheap inert gas being as the cushion gas is needed to maintain reservoir pressure and ensure the stability of gas storage. In recent years, injecting CO2 for use as the cushion gas has drawn great attention for its potential to sequestrate the greenhouse gas underground and improve the operating efficiency of the working gas. In this study, a three-dimensional component model coupled with convection and diffusion is firstly constructed to describe the flow and miscible displacement processes affected by mixing in the porous media surrounding storage wells, and a fully implicit numerical model is established based on unstructured tri-prism meshes and a hybrid control volume finite element (CVFE) and finite-difference (FD) method. Secondly, mixing experiments of CO2 as cushion gas are carried out, the results are verified by numerical model, and good agreement between measured and computed data is achieved. Finally, through the numerical simulation of the hypothetical cases and orthogonal experiments, it is can be concluded that: CO2 is more suitable as cushion gas than natural gas itself and N2, injecting CO2 through corner wells at the bottom layer can effectively prevent the working gas escaping, and help to store more CO2 and slow down the mixing zone runs up, and the high production rate will help to control the mixing zone at a lower position and obtain greater gas recovery.

An Express Methodology for Calculating the Reliability of Power Supply Systems with Autonomous Power Sources

Autonomous power sources are widely used in systems for power supply to industrial facilities, especially in the oil and gas industries that have affordable energy carriers. These sources can be used both separately and in combination with centralized power supply, as primary, backup, or emergency sources. Their operation is characterized by the features that affect power supply reliability and must be taken into account when deciding on their use in the stages of designing new power supply systems or modernizing existing ones. The use of methodology and software for calculating the reliability of systems with autonomous power sources in the stage of pre-project research can contribute to more informed decision-making. In this stage, there is no need and opportunity to consider all reliability issues in detail. Here, express methods are enough to take into account the main features of the systems functioning with autonomous or mixed power sources and to compare the proposed system options within a single methodological framework. Based on this, a methodology was developed to calculate the reliability of power supply systems with autonomous and mixed power sources. The proposed methodology employs semi-Markov random processes (Markov chains) and can be used in comparative reliability analysis of power supply options with autonomous and mixed power sources. It was implemented in software and is accompanied by an example of reliability calculation for power supply to a stationary platform for maintaining reservoir pressure in an offshore oil field.

Catastrophe-theory-based Health Condition Evaluation for Centrifugal Pump Unit

Centrifugal pump is an important kind of water injection equipment used to maintain reservoir pressure in oilfield development. The health condition evaluation of centrifugal pumps is helpful to improve the operation and maintenance level. Although Analytic Hierarchy Process (AHP) and fuzzy evaluation method are widely applied in health condition assessment, there are still some problems, such as the determination of weight is greatly influenced by subjective factors and the calculation is complicated. To solve the above problems, this paper puts forward a catastrophe theory evaluation model combining fuzzy mathematics for the evaluation of centrifugal pump. Firstly, the structure, common faults model and operation mechanism of centrifugal pump units were considered, a multi-level security evaluation index system was established; combined with fuzzy mathematics, the bottom indexes used to evaluate centrifugal pump unit was calculated by dimensionless method; and various indicators of the impact of centrifugal pump operation have been processed with standardization and normalization. Secondly, the total security membership value layer by layer was obtained by using the security membership value of the underlying index layer, recursive quantization. Finally, the health level of the centrifugal pump unit was obtained according to the scores obtained by the catastrophe progression. The method takes the advantage of avoiding the quantification of assessing indexes and the choice of parameter values. Thus, the results of this evaluation model are reliable, and the evaluation method is objective, accurate and has a high value in engineering.

METHODS FOR ACCURATE AND RAPID RESEARCH OF POTENTIAL WELL PRODUCTS

Background The article discusses the method of physical feasibility of oil recovery processes based on the systematization of potential flow rates and current reservoir pressures, which is associated with the improvement of the system for maintaining reservoir pressure and selection of well production when combining oil displacement modes, research and plugging unproductive sections of layers. Aims and Objectives Increasing the accuracy of determining the vectors of input and output coordinates in the form of potential flow rates of injection and production wells, which affect changes in current reservoir pressures during extreme regulation of oil recovery processes. Results The required conditions for combining oil displacement optimization sub-cycles in metatechnology of hard-to-recover reserves production with sub-cycles of research and plugging of unproductive sections of reservoirs are fulfilled provided that the ratio of well flow rates and current values of in-situ pressures changes. At the same time, the fundamental in determining the flow rates of well fluids is the need to take into account changes in the values of the compressibility, thermal expansion and gas solubility coefficients.

Data-driven proxy model for waterflood performance prediction and optimization using Echo State Network with Teacher Forcing in mature fields

Waterflood has been widely applied across the world as the most important secondary recovery process to improve reservoir performance. The schemes applied to waterflood projects involve key decision-making which aims to maximize the net present value (NPV) for a given period, improve recovery and sweep efficiency, maintain reservoir pressure, reduce water production, and avoid water recycling. Traditionally, the preferred approach to estimate the future performance of any given waterflood project is through the numerical reservoir simulation. However, despite the great power and intuition associated with the simulation models, sometimes this potential is unachievable due to massive computational requirements. Also, in some other cases, there may exist no simulation model to begin with. To tackle these problems, data-driven proxy models are proposed. In this research, we propose a novel machine-learning-based proxy model for waterflood performance prediction and further apply it for production optimization purpose to obtain the optimal future well control. The data-driven model is realized using the Echo State Network (ESN) under the paradigm of “Reservoir Computing” (RC). Compared with traditional ESNs, this specific methodology includes a feedback loop from the output into the high dimensional “reservoir” to achieve improved prediction results for separated phase production rates. Teacher Forcing (TF) technique is used for easier incorporation of the feedback information without introducing additional recurrent loops during the training process. Furthermore, training ESN proxy models utilizes Ridge Regression, thus all calculations within have analytical solutions that guarantee much improved speed when evaluating forward model-runs, which further lowers the computational demand during the optimization process. The proposed workflow is typically more suitable for mature fields since reliable production data after breakthrough from each producer could greatly improve the training process, and it can be used under the circumstance where no reservoir model has been established. In this research, we present two test examples where we apply ESN to learn the reservoir simulation results of waterflood and further perform open-loop optimization on each of them.

Pyrolysis of heavy oil in supercritical multi-thermal fluid: An effective recovery agent for heavy oils

As a novel thermal agent, supercritical multi-thermal fluid (SCMTF) has great potential to be used for heavy oil reservoirs. However, its viability and enhanced oil recovery (EOR) mechanisms have not been investigated. Therefore, a series of tests were conducted in a newly designed autoclave to compare crude oil pyrolysis in steam, supercritical water (SCW), SCW + supercritical nitrogen (scN2), SCW + supercritical carbon dioxide (scCO2) and SCMTF, and the viability of SCMTF was evaluated. Then, the possible mechanisms of pyrolysis in SCMTF were proposed. Finally, the effects of temperature, pressure, and the amount of SCMTF on pyrolysis in SCMTF were investigated. The results show that the SCMTF treatment of raw crude oil at 653 K and 23 MPa resulted in molecular weight, density and C15+ content reduction rates of 44.67%, 6.45% and 12.06%, respectively, and gave a gas yield of 7.91 wt % and an increase in the light oil fraction of 10.17 wt %. SCMTF is more effective than steam, SCW and SCW + scN2 for upgrading heavy oil. In detail, SCW dominates the pyrolysis processes; scCO2 accelerates dealkylation, and increases oil mobility by dissolution and light hydrocarbons extraction; and scN2 can maintain reservoir pressure and form a gas-cap, which reduces heat loss. Increases in scCO2 fraction, temperature, pressure and the amount of SCMTF can enhance the heavy oil upgrading. However, pyrolysis at a high temperature is adverse to light oil production (the oil product yield was merely 67.10% at 683 K) due to undesirably high gas and coke yields of 13.32% and 19.58%, respectively.

Impact of Nitrogen Injection on Pore Structure and Adsorption Capacity of High Volatility Bituminous Coal

Nitrogen is often injected into coalbed methane (CBM) reservoirs to enhance the recovery by maintaining reservoir pressure and elevating permeability. Its effectiveness as a stimulant relies on imp...

Efficient History Matching of Thermally Induced Fractures Using Coupled Geomechanics and Reservoir Simulation

Waterflooding is a common recovery method used to maintain reservoir pressure and improve reservoir oil sweep efficiency. However, injecting cold water into a reservoir alters the state of in-situ formation stress and can result in the formation fracturing. In other words, it can cause the initiation and growth of thermally induced fractures (TIFs), even when the original fracture propagation pressure is not exceeded. TIFs can cause non-uniform distribution of the fluid flow in wellbores, a reduction in sweep efficiency, and early water breakthrough in nearby production wells. Modelling and history matching workflows that consider the dynamic nature of the TIF problem are critical. These workflows improve and validate reservoir and geomechanical models, identify and confirm observed TIF onset and propagation periods, and provide a history-matched sector model with the rock mechanical and thermal properties and stress gradients that can be used with confidence for subsequent studies. Modelling and the underlining assumptions of fluid flow in the TIF and reservoir matrix, as well as geomechanical changes due to cooling of the reservoir during injection, are detailed below. A 3D reservoir simulator coupled with 2D finite element TIF and geomechanical models were used to manually history match an injector (NI6) in the N Field sector reservoir model in which a TIF was observed. In this study, history matching workflows were developed to consider the dynamic nature of TIF development during waterflooding. The reservoir and geomechanical models were improved and validated via the observed TIF onset and propagation periods. The history-matched models produced can be used with confidence in subsequent studies. The practical workflows and guidelines developed here can be used in waterflooding operations during the modelling, design, and planning stages. The novelty of this study is the coupling approach of different complex processes done in order to capture dynamic changes during waterflooding operations. A similar history matching study could not be found in the literature.

Overcoming Challenges in Chemical EOR During Polymer Breakthrough

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 194689, “Challenges in Selection and Use of Production Chemicals With Chemical EOR Operations During Polymer Breakthrough Phase,” by Robert Zagitov, Panneer Selvam Venkat, and Ravindranthan Kothandan, Cairn Oil and Gas, et al., prepared for the 2019 SPE Oil and Gas India Conference and Exhibition, Mumbai, 9-11 April. The paper has not been peer reviewed. In chemical enhanced oil recovery (EOR), challenges are expected regarding production chemistry and production-facilities operations. Partially hydrolyzed polyacrylamide (HPAM) is used widely for controlling mobility ratios. Complex in water chemistry and rich in positively charged divalent ions, flooded polymer, having a negative charge, interacts with divalent ions of produced water (PW). The complete paper discusses the importance of adequate preparation and the approaches used to overcome challenges of EOR operations, including handling back-produced polymer. Introduction The Mangala field in northwest India, discovered in January 2004, is part of the Barmer Basin. The primary reservoir unit in this field is the Fatehgarh group, a high-quality quartzose sandstone reservoir having high net-to-gross ratio, high porosity (21-28%), and multidarcy permeability (200 millidarcy to 20 darcy) with an average permeability of approximately 5 darcy. The reservoir contains waxy crude with gravity ranging from 20 to 28 °API. A primary recovery efficiency of less than 10% stock-tank oil initially in place is estimated on the basis of simple depletion; thus, the base field-development plan envisaged implementation of waterflooding from the start of production to maintain reservoir pressure and sweep reserves. Detailed laboratory studies have established that aqueous-based chemical EOR processes are best suited for these viscous oil fields. Full-field polymer flooding has been implemented in the Mangala field, with an injection at the time of writing of nearly 400,000 B/D of polymerized injection water (IW) with average polymer concentration of approximately 2,500 ppm. HPAM is mixed with source water to create a mother solution of 15,000-ppm concentration at a central polymer facility and is distributed through a pipeline network to 15 well pads, where it is diluted with IW to achieve a viscosity of approximately 30 cp for injection. Artificial lift is achieved either by jet pump or electrical submersible pump. Average water cut is 80% at the time of writing.

Analysis of permafrost conditioning in the oil field

Based on model concepts, the technique of maintaining the stability of the permafrost layer is analyzed. An injection well is considered as a reference channel for injecting a mixture of liquid and gas. The purpose of this technology is to control the flow of heat. The development of hydrocarbon deposits in the extreme north requires the preservation of perennial frozen soils in a stable solid state. Stable condition of frozen soils is a guarantee of well operability. An injection well is used to inject refrigerant into the frozen soil zone. When using packers to separate said portion, the injection process to maintain reservoir pressure may continue in the usual manner. Permanent frozen soils are conditioned using a mixture of liquid and gas. This mixture allows you to control the parameters of temperature, pressure and heat capacity over a wide range. The directions of the mixture are formed using a packer system. Packers are installed in the tubing and in the annulus. The formation of a coolant agent is organized directly in the well above the working formation. The technique of ejector pumps is used. The ejector is a device for controlling the parameters of the mixture. The components of the mixture are fed through columns (pipes). The organization of the movement of components is considered as an additional degree of freedom. The proposed technology allows you to use an additional option for the operation of the existing layout of wells in the oil and gas field. The usual practice of the operation of the fishery may remain unchanged.

An offshore reservoir monitoring system based on fibre-optic distributed sensing of seabed strains

Abstract One of the problems affecting mature hydrocarbon fields, e.g., Ekofisk, Tyra, and Dan in the North Sea, is seabed subsidence due to reservoir depletion. Fluid injection is a widely used method to boost production and/or maintain reservoir pressure in order to mitigate compaction and subsidence. Both reservoir depletion and fluid injection operations might induce seabed deformations. The deformation pattern potentially holds useful information about production efficiency and reservoir management, which could be captured by careful monitoring of seabed strains. Therefore, the idea suggested herein was performing near full-field and continuous monitoring of seabed deformations by means of distributed fibre-optic strain sensing. The objective of the study was to theoretically calculate and assess whether current technologies (i.e., off-the-shelf optical interrogators) are accurate and sensitive enough to detect production-induced seabed strains originating at a 2 km-deep reservoir. The analysis indicates that depletion-induced subsidence is potentially measurable with seabed distributed fibre-optic strain sensing. However, the operation of an injector-producer array induces seabed strains that are too small to be detected with current capabilities.

ИССЛЕДОВАНИЕ ЭФФЕКТИВНОСТИ КОМПЛЕКСНОГО НЕСТАЦИОНАРНОГО ВОЗДЕЙСТВИЯ НА ЗАЛЕЖЬ С ВЫСОКОВЯЗКОЙ НЕФТЬЮ

Актуальность. При стационарной закачке воды для поддержания пластового давления наблюдается опережающее обводнение добывающих скважин. Преждевременное обводнение связано с высокой послойной и зональной неоднородностью коллекторов, высокой вязкостью нефти, подошвенной водой, интенсивной закачкой воды. Использование циклического заводнения позволяет увеличить охват пласта воздействием и текущий коэффициент извлечения нефти. Прирост в добыче нефти от использования метода достигает 4 %, снижается отбор воды из залежи. Цель: исследовать эффективность использования циклического заводнения на залежи с высоковязкой нефтью, оценить наиболее эффективную длительность периодов работы и остановки нагнетательных и добывающих скважин для достижения наибольших приростов в добыче нефти. Объект: участок турнейской карбонатной залежи с высоковязкой нефтью. Средняя обводненность продукции скважин на залежи составляет 77,1 %, при отборе от начальных извлекаемых запасов – 49 %. Участок эксплуатируется одной нагнетательной скважиной, расположенной в центре, и девятью добывающими скважинами по периметру водонефтяного контакта. В рассматриваемых условиях необходимо внедрять методы увеличения охвата паста воздействием и снижения обводненности. Методы: определение оптимальных технологий циклической закачки воды и комплексного нестационарного воздействия, гидродинамическое моделирование циклического воздействия на участке нефтяного месторождения. Результаты. Рассмотрены различные варианты работы нагнетательной скважины при реализации циклического заводнения. Получено, что соотношение продолжительности работы и остановки скважины, при условии 100 % компенсации, практически не влияет на результат моделирования. При циклической работе нагнетательной скважины увеличение добычи нефти происходит на 3,6 % по сравнению с базовым вариантом. Больший технологический эффект возможен при комплексном воздействии – периодической остановке как нагнетательных, так и добывающих скважин. В случае комплексного воздействия накопленная добыча нефти на участке залежи увеличивается на 10,6 % по сравнению с базовым вариантом.

Colmatation of reservair rocks in the operation of oil fields as a result of cation exchange

By analyzing the changes in seawater pumped to maintain reservoir pressure (FPD), the anhydrous granitoid reservoir of the White Tiger deposit, in which the cracks are partially filled with calcium minerals (calcite and lomontite), shows that these minerals interact with the injected seawater. Hydrogeochemical modeling of this process showed that cations of seawater are first sodium and then magnesium displace calcium from the lomonite exchange complex, which leads to precipitation of anhydrite and a small amount of calcite. The incoming water dissolves the anhydrite and precipitates it downstream, forming a gradually expanding annular region with a constant increase in the amount of precipitated anhydrite. As a result, there is a decrease in the permeability of the fracture medium due to the filling of the cracks with anhydrite. A large amount of calcium in the associated waters when they rise to the surface causes the precipitation of calcite in the production wells and surface equipment. The transition of drilling to ever greater depths, where the rocks contain lomontite almost everywhere, requires taking into account the phenomena of cation exchange between the injected water and the rock in the predictions of scaling.