Maintain Reservoir Pressure Research Articles

Feasibility Study on Geothermal Dolomite Reservoir Reinjection with Surface Water in Tianjin, China

Reinjection is thought to be the most effective way to maintain reservoir pressure and production capacity for hydrothermal resources. The use of external water injection to replenish deep geothermal reservoirs is a new approach in China to addressing the problems of declining groundwater levels and energy depletion caused by the excessive and uneven exploitation of geothermal resources. However, the key challenge and focus of the feasibility assessment of this method lies in the chemical compatibility of the external water with the native geothermal reservoir water and surrounding rocks. In this paper, we discuss the geochemical response of a dolomite reservoir to lake water injection based on experiments on water–rock interaction in the Wumishan formation in the Dongli Lake area of Tianjin. The results show that after reactions with dolomite, the TDS of the reacted water decreases, indicating the occurrence of precipitation. According to the calculation results obtained using the PHQREEC program, the precipitation amount is found to be quite limited. Geochemical analysis indicates that at the initial stage of the reactions, plagioclase dissolves and releases alkaline metals like Ca-, Na-, SiO2- and Al-bearing compositions, leading to the oversaturation and precipitation of dolomite and calcite. As the reaction progresses, a portion of the dolomite dissolves, while the calcite continues to precipitate at a later stage. Illite precipitates and its effects on reservoir structure depend on its shape. Based on the experimental data, it can be concluded that the dolomite reservoir will be slightly affected by the reinjection of lake water; however, it is still a good method for the sustainable development of geothermal resources.

Accounting for a capillary pressure jump in a saturated porous medium for a more correct calculation of hydrocarbon reserves

Relevance. The correct calculation of hydrocarbon reserves in various fields (oil, gas, gas condensate) is an important state task, because it allows you to properly organize field development in the future and ensure the rational use of natural resources of the state. In particular, the values of geological and recoverable reserves are assigned to a specific subsurface user and are recorded in departmental documents. Aim. To describe the effect associated with the calculations of the thermodynamic equilibrium of the mixture of hydrocarbons of the Karachaganak oil and gas condensate field at various formation depths with the capillary pressure jump taken into account. This makes it possible to clarify the value of the potential condensate-gas factor of reservoir gas and, as a result, to give a more accurate assessment of the geological reserves of hydrocarbon raw materials. Object. Analysis of the thermodynamic equilibrium of the hydrocarbon mixture of Karachaganak oil and gas condensate field, taking into account the capillary pressure jump, which takes place in a porous medium under reservoir conditions. Methods. Numerical modeling, analytical research. Results. Based on the previously developed methodology for calculating the phase equilibrium with the capillary pressure jump the correction of the potential condensate-gas factor of the formation gas of the Karachaganak oil and gas condensate field was carried out at various formation depths. The range of values of the condensate-gas factor difference for calculations both with and without capillary pressure jump was from 7,04 g/m3, with a condensate-gas factor value equal to 393 g/m3 for formation depth of 4000 m, to 64,47 g/m3, with a condensate-gas factor value equal to 547 g/m3 for formation depth of 4600 m. Based on the updated condensate-gas factor estimate, it is possible to clarify the condensate recovery coefficient during the development of a field without maintaining reservoir pressure or with partial maintaining reservoir pressure.

Production optimization in a fractured carbonate reservoir with high producing GOR

The Gas-Oil Ratio (GOR) is a crucial production parameter in oil reservoirs. An increase in GOR results in higher gas production and lower oil production, potentially leading to well shut-ins due to economic infeasibility. This study focuses on a real fractured oil field that requires urgent production operations to reduce the producing GOR. In this study, the static model for the field was developed using commercial software, involving steps such as data collection, fault modeling, meshing, and statistical analysis to prepare for dynamic simulation. The dynamic model incorporates geometry, gridding, and rock properties from the static model, utilizing a dual-porosity approach for the naturally fractured reservoir and the Peng-Robinson equation for fluid phase behavior. Initial reservoir conditions, production history, and rock-fluid interactions were defined, with relative permeability curves indicating a water-wet reservoir and low critical gas saturation affecting the GOR. To better understand the relationship between reservoir and production parameters, a detailed sensitivity analysis was performed using the Response Surface Methodology (RSM). Following the sensitivity analysis, a history matching process was conducted using the Designed Exploration and Controlled Evolution (DECE) optimizer to validate the model for future forecasts. Six operational scenarios were defined to decrease the production GOR and enhance final recovery from the field. The results indicate that the water injection scenario is effective in preventing the GOR increase by maintaining reservoir pressure, thereby sustaining production over a longer period. This scenario also improves oil recovery by approximately 6% compared to the base case. Finally, optimization was carried out using the DECE optimizer for each scenario to fine-tune the operational parameters. The goal was to maximize oil revenue for each scenario during the optimization process. This study stands out as one of the few that provides a comprehensive analysis of production behavior and development planning for a real fractured reservoir with high producing GOR.

Setup of PVT-models. Modeling of injection wells. Configuring models of collection system and pipelines and reservoir pressure maintenance system

Relevance. The ability to provide more accurate and efficient assessment and management of hydrocarbon production using software products for integrated field modeling. However, this approach requires an analysis of the source data quality, as well as the selection of the correct approach to creating models. Consistent and systematic work makes it possible to reproduce the actual situation with high accuracy in order to use the results obtained in further work. The integrated field model is a completely new approach to field development, when current work is based not on existing solutions, but on potential. Forecasting the behavior of the reservoir, wells and infrastructure, the collection system and the system for maintaining reservoir pressure allows for a comprehensive assessment of the possibilities of obtaining maximum oil and gas production while minimizing possible losses. Aim. Formation and analysis of an approach to setting up PVT-models of fluids, models of injection well stock, collection and transport systems and reservoir pressure maintenance systems by adapting parameters to actual data. Methods. Setting up and adapting injection well models; setting up and adapting collection system and pipeline models; approach to work with the reservoir pressure maintenance system. Results. The results obtained make it possible to adapt the components of the integrated model with an accuracy of over 95 %, which makes it possible to simulate the operating conditions of the field. Because of the analysis, tuning criteria were identified, and the minimum required set of parameters for high-quality adaptation of models was presented. Efficiency and accuracy of predictive calculations on adapted models has also been proven by comparing actual performance data with synthetic data. Based on the work done, we can conclude that the use of an integrated model shows us a high convergence with real data, which allows us to optimally approach the field development regime.

INFLUENCE OF NATURAL FACTORS OF SUPPORTING RESERVOIR PRESSURE AT THE LATE STAGE OF DEVELOPMENT OF GAS CONDENSATE FIELDS

The object of the research is natural factors that can affect both the maintenance of reservoir pressure in the process of developing gas condensate fields and the recovery of depleted deposits. Such factors include: waterflooding of deposits, subsidence of the surface, elasticity of rocks, water and gas, initial gradients of reservoir pressure in deposits, capillary forces. When studying the recovery of reserves in depleted gas condensate fields, it is necessary to take into account the influence of the above factors on the maintenance of reservoir pressure in order to identify the volumes of gas that flow from deep horizons (external sources). The paper shows the dynamics of waterflooding volumes and average reservoir pressures over the years. It is emphasized that waterflooding does not significantly affect the maintenance of reservoir pressure. Correlation dependencies of waterflooding volumes over time and the dependence of waterflooding volumes on reservoir pressure are given. An original system for calculating the volume of the water pressure system is proposed for the purpose of forecasting further waterflooding of deposits. The influences of all the above factors on the process of maintaining reservoir pressure are taken into account. It is shown that for the Shebelinsky GCF, all these factors do not significantly affect the recovery of reserves. The influence of capillary forces and evaporation of water in deposits on the development processes from the point of view of maintaining reservoir pressure at the late stage of GCF operation is studied.

Обоснование снижения концентрации кислотного состава при проведении обработок призабойных зон скважин на нагнетательном фонде с 12 до 8 %

The substantiation of the application of a new technology for treatment of bottom-hole zone (hereinafter referred to as BHZ) treatment of injection wells with reduced concentration of acid compositions. Maintaining reservoir pressure during field development is carried out by injecting water into the formation in the bottom hole-zone through injection wells, as a result of which, over time, the filtration characteristics of the formation in the near-wellbore zone deteriorate. In order to clean the bottom-hole zone and, as a result, increase the pick-up rate of injection wells, acid stimulation is performed. The article is based on the world experience of treatment of injection wells using 12% acid composition, as well as on the technology of treatment of bottom-hole zones of injection wells of the Northern Caspian fields with 8% acid compositions. Bottom-hole zone treatment technology is applied at all stages of oil field (deposit) development. Bottom-hole zone treatments are carried out based on actual injectivity indicators and/or after geological and technical measures have been taken at the reservoir. LUKOIL-Nizhnevolzhskneft facilities traditionally use 12% acid compositions for treatment of terrigenous reservoirs, which are selected based on the results of laboratory tests for the current reservoir conditions. The BHZ technology includes sequential treatment of bottom-hole zone and down-hole equipment deposits with hydrocarbon solvent, surfactant solution and acid composition. At that, the technology of work execution (sequence, injection speed, quantity of reagents, number of packs, etc.) is determined by specialists depending on the composition and layout of down-hole equipment, physical and chemical characteristics of the formation (thickness, porosity, permeability, bottom-hole temperature, formation pressure, rock composition) and economic evaluation. The article focuses on the principles, technologies and compositions of solutions used in the North Caspian fields.

Design and research of the plunger pump mechanism for pumping liquid in reservoir pressure maintenance systems

Nowadays, plunger pumps have the most advanced designs. In fact, plunger pumps are the only ones of their kind, capable of operating at high pressures and have the best characteristics. Their use is growing in industry, as they cope with the harsh conditions of pumping liquids of various types. To maintain reservoir pressure, pumps require a high efficiency and reliable design. In order to ensure the operability of the system, it is necessary to select qualitative indicators according to the criteria of optimality for the design of mechanism parts and to achieve an adequate workflow. Thus, the study and determination of the possibility of improving the performance of plunger pumps remains a current task. The results presented in this article include an analysis of the operating conditions of each of the components of the mechanism using a mathematical model of the drive based on the differential equations of motion of the plunger pump, the determination of the corresponding production processes and the production of finite elements. In addition, a kinematic force analysis of the functions of the mechanism under study (positions of analogues of speeds and accelerations of links) and the found motion characteristics is carried out when solving the problem of dynamics of the main shaft of the machine. This article presents a test report to verify the correct functioning of the mechanism in accordance with the initial parameters of the system, the design of a gear planetary gearbox with cylindrical wheels, a cam mechanism pusher and their type of assembly to be performed. This research is carried out using software for engineering mathematics: Mathcad and Python.

RESEARCH OF FORMATIONS INJECTIVITY IN ORDER TO ORGANIZE RESERVOIR PRESSURE MAINTENANCE IN THE CARBONATE FIELDS

In this item, the top-priority is organization of reservoir pressure maintenance system and fields development under natural mode in order to maintain reservoir pressure in carbonate fields. Currently, the fields are being developed in a natural drive, and arranging a system for maintaining reservoir pressure is a top-priority. Carbonate fields are complicated by tectonic faults in the separate blocks and HC production reveals disturbance of the balance in the geological environment. Longtime fluid sampling without reservoir pressure maintenance leads to change of stress fields in formation, which initiates creation of deformations of earth surface. In order to prevent from these events, it is required to maintain reservoir pressure. It is necessary to maintain reservoir pressure to prevent these events from happening. When water is injected, migration occurs through a complex ramified system of cracks, caverns and pore channels. The most permeable in the productive thickness layer are karst intervals and zones of increased fracturing, which serve as the main routes for fluid migration. Considering complication of RPM system organization due to high wellhead pressure, field distance from water sources and possible creation of cavity and carst, conception of carbonate fields development is developed within the frame of item.

FORECASTING ORF BY THE MARTOS METHOD AND THE STATISTICAL METHOD USING THE EXAMPLE OF DEPOSIT X

The article discusses the effectiveness of the Martos method and the statistical method for predicting oil recovery factor using the example of the X field. Today's values of oil recovery factors (ORF) for Triassic horizons were determined taking into account the active water pressure regime with artificial maintenance of reservoir pressure (RPM) and the drilling of 16 new production wells. This approach required a revision of ORF values due to the transition to natural reservoir development and the cessation of maintaining reservoir pressure by water injection. The failure to drill new wells has also had a significant impact on ORF. At current production, when 44.7% of the field's reserves have been extracted, and taking into account the remaining reserves, the development period of the field will not exceed 42 years. It is also planned to increase the number of hydraulic engineering measures to expand drainage zones and involve additional reserves in development. Having compared the two methods for calculating ORF, we can conclude that although V.N. Martos’ method is based on reservoir parameters, and the statistical method uses historical data, the results of their calculations differ slightly.

About flooding of low-permeable formations

Due to the depletion of hydrocarbon reserves in traditional reservoirs with good filtration and reservoir properties, there is currently increasing interest in hard-to-recover reserves, and the main difficulty in developing such reservoirs is the efficiency of reservoir pressure maintenance systems. When developing low-permeability reservoirs, various mechanisms of oil displacement during flooding can be distinguished. For reservoirs with permeability less than 1 mD, there is no need to maintain high wellhead pressure; moreover, with a large accumulated compensation, stopping the maintenance of reservoir pressure for up to six months does not lead to a drop in production, which creates the prerequisites for organizing cyclic flooding. This will solve a number of problems that arise while maintaining reservoir pressure when working in such conditions.
 The facies structure of reservoirs sometimes has a decisive influence on the performance of wells and their interinfluence. The transition to the development of fields with a complex geological structure, low filtration characteristics of the formation, the existence of geological bodies with different properties requires not only careful formation of a conceptual understanding of the field, but also the creation of detailed facies digital maps taking into account the existence of zones with different sedimentation, which, as a consequence, creates zones with different filtration and capacitance properties, requiring different approaches to development.

THE CORRELATION BETWEEN WATER INJECTION VELOCITY AND DISPERSION COEFFICIENT IN HOMOGENEOUS AND HETEROGENEOUS RESERVOIRS

Water injection into porous media serves various purposes such as maintaining reservoir pressure, wastewater removal, and enhancing hydrocarbon production recovery. One significant challenge in the water injection process is the formation of mineral scale due to the incompatibility between the injected water and the formation water. The dispersion coefficient, which characterizes the behavior of different ions in mixed waters, is a critical factor in water flooding studies. It determines the size of the mixing zone during miscible processes. This study calculates the dispersion coefficient using non-interacting and non-precipitating tracers in both homogeneous and heterogeneous cores. Experimental data were mathematically modeled, revealing previously unreported correlations between the dispersion coefficient and injection velocity for both types of rocks.

Efficiency of maintaining reservoir pressure in oil wells during the development of carbonate reservoirs

The paper analyzes the operation dynamics of injection and observation production wells. It assesses the impact of injection wells on produced water density. The reservoir is characterized by out-contour flooding. It was found that such a scheme is ineffective due to the weak hydrodynamic relationship of the reservoir with the aquifer, which is confirmed by the result of this analysis, and the selective (focal) water flooding used on the Kizelovsky horizon also does not have the proper effect, and there is no correlation of formation pressure with injection in observation wells. It was shown that large volumes of water injection into injection wells do not maintain formation pressure in certain areas, but in general, there is a slight positive impact on the development indicators for the target. The recommendations for optimizing the formation pressure maintenance system were proposed based on the results of the analysis.

Technology advancement of maintaining reservoir pressure in oil carbonate fields

In the work, based on a comprehensive analysis of geological and field information and the dynamics of technological indicators of field development, the effectiveness of the applied waterflooding system was evaluated and the results obtained were compared with the theoretical foundations of the method.The study used a set of well-known geological technological methods used in oil and gas production: mathematical modeling to establish the dependence of the oil displacement ratio by water on the permeability of the reservoir and the average annual water cut of well production from the volume of injected water; hydrodynamic calculations in determining the oil recovery factor in natural conditions; mathematical statistics to determine the accumulated oil production over the entire development period and its recovery factor; experimental studies in determining the coefficient of oil displacement by water.It is shown that: productive horizons confined to a single reef complex significantly differ in the degree of geological heterogeneity; due to the isolation of the aquifer, the natural mode of operation of productive horizons is closed-elastic with a transition to the mode of dissolved gas; the dynamics of the growth of water cut and oil production indicate an insignificant role of fracturing in the process of its extraction; a development system with areal water injection under the oil-water contact and a dense grid of production wells, where a phased transfer of sampling intervals was carried out, made it possible to more than double the oil recovery factor; the effect of waterflooding was obtained due to the achieved high values of sweep efficiency and waterflooding sweep efficiency.

К ВОПРОСУ ПОДГОТОВКИ ВОДЫ, ИСПОЛЬЗУЕМОЙ ДЛЯ СИСТЕМЫ ЗАВОДНЕНИЯ, ПРИ УСЛОВИИ ОБЕСПЕЧЕНИЯ ЭКОЛОГИЧЕСКОГО МОНИТОРИНГА ПРОЦЕССА

The research results presented in the article have shown that when using different types of water to maintain reservoir pressure, the technological schemes of water treatment plants have significant differences. The impact of the processes of reservoir flooding on the state of the territory, the inconstancy and complexity of the composition of the waters used to maintain reservoir pressure, necessitate continuous environmental monitoring in the area of influence of the oil and gas field

Application of Integrated Evaluation on Seawater Injection to Improve Injectivity for Carbonate Reservoir in Offshore Oilfield

Seawater flooding is popular for carbonate reservoirs in offshore oilfields and seawater is sometimes the unique choice of injection water source due to the lack of surface water supply. Seawater is injected into reservoirs to maintain reservoir pressure after water treatment for technically and economically effective field development. Uneven injection and production in B oilfield caused unbalance of pressure distribution and poor injection performance. It is essential to improve the injectivity of single well to a satisfied level through a integrated workflow on the basis of performance analysis, brine compatibility study, core flooding experiment, strategy and solution optimization. In this paper, the injection status has been analyzed and the decisive impacting factors were given including formation properties, stimulation activity, the brines compatibility and pre-treatment of injection water, which play a very important role in injection performance sustainability as the seawater injection continues. Scale modelling was done with formation water, mud filtrate, injection water and stimulation fluid for self-scaling assessment. Mixing experiment of two of the brines of four introduced at either atmospheric or reservoir condition. Core flooding experiment was carried out with formation water and filtered injection water after critical velocity for core flooding is confirmed. Then the injectivity for each wells have been analyzed at different locations of the reservoir with different formation properties, solutions have been subsequently put forward and the improvement on injectivity of injectors before and after the stimulation or even re-stimulation and the effect of cleanup after the stimulation was also compared. It was concluded that injectivity could be enhanced through stimulation and the cleanup after stimulation and the sulfate should be removed or reduced in the process of the pre-treatment of injection water from the remote terminal to ensure desirable water injection and production performance.

Increasing the profitability of production of hard-to-recover oil reserves based on the choice of a rational development system

The article presents a solution to the problem of determining the most effective system for the development of hard-to-recover oil reserves confined to thin-layered clay-bearing reservoirs, based on geological and hydrodynamic modeling. The ratio of oil recovery factor and net discounted income was used as an assessment of the project efficiency. When selecting, the profile was varied - a directional well with hydraulic fracturing and a horizontal well with multi-stage hydraulic fracturing, the method of organizing the system for maintaining reservoir pressure, the density of the well grid and the technological parameters of well completion - the length of the horizontal section and the distance between the hydraulic fracturing sleeves. To confirm the results obtained, an analysis of the operation of the wells launched at the facility was carried out, which showed the convergence of the rate of decline in production rates in the absence of the involvement of the underlying horizon by a hydraulic fracture. Additionally, when choosing a site for pilot work, an option was considered to use the existing well stock to organize a reservoir pressure maintenance system while maintaining the geometry of the development element. According to the calculations, the application of the developed solutions will make it possible to double the oil recovery factor and the net discounted income of the project compared to the base case.

Application of thermotolerant petroleum microbes at reservoir conditions for enhanced oil recovery

Primary oil recovery is the first stage of hydrocarbon production in which a reservoir uses its natural energy to force hydrocarbon to its wellbore. Secondary oil recovery comes to play when hydrocarbons can no longer be further produced by natural means. The purpose of secondary recovery is to maintain reservoir pressure so as to displace hydrocarbons toward the wellbore. Both primary and secondary recovery processes cannot displace more than 50% of the available hydrocarbons in a reservoir. The remaining hydrocarbons are further recovered through Tertiary/Enhanced Oil Recovery techniques. According to literature, microbial enhanced oil recovery has been identified as a tertiary method used to improve the efficiency of hydrocarbon production from reservoirs. Microbial enhanced oil recovery is a feasible reservoir technology, which has not been widely used in the oil and gas industry owing to the attainment of the requisite reservoir conditions such as temperature within which microbes can thrive. Literature has shown that thermotolerant microbes can withstand optimum temperatures of 50–90°C, while deep and ultra-deep hydrocarbon reservoir temperatures are often above 100°C. This study identifies some isolated thermotolerant microbes from a sandstone reservoir that can withstand temperatures as high as 110°C via conventional methods and molecular analysis. The identified thermotolerant petroleum microbes: Bacillus amyloliquefaciens ( A) and Bacillus nealsonii (B) were used to enhance oil recovery from a reservoir. The results showed that the microbial species A and B at a confined pressure of 3.0 MPa and temperature of 27°C, gave 46.4% and 48.6% oil recoveries, respectively, which is comparably higher than the value (26.9%) obtained for the water flooded samples. At temperatures of 80, 90, 100, 110 and 120°C, the oil recovery results show that the recovery factor (55.2–64.1%) of species B were higher compared to the range (46.7–57.5%) recorded for species A. At the onset of the core flooding experiments, there was an initial increment in oil recovery factor as the temperature increased from 80 to 110°C, whereas, it remained constant within 110–120°C. This trend coincides with the drop in the thermal resistance exhibited by the microbes when exposed to such conditions. The cumulative oil production from the commercial Eclipse simulation closely matched those of the experiment results, whereas, the slight difference can be attributed to the adjustment of the simulation input parameters. The experimental results show that species B can be used to enhance oil recovery at reservoir temperature conditions above 100°C.

Efforts Lead to Formulation of High-Performance ASP

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 22729, “ASP Formulation Development Journey: Optimization, Validation, and Quality Control for Mangala Field,” by Nitish Koduru, Dhruva Prasad, SPE, and Amitabh Pandey, SPE, Cairn Oil and Gas. The paper has not been peer reviewed. Copyright 2023 International Petroleum Technology Conference. Reproduced by permission. _ Mangala is a large low-salinity, high-quality fluvial oil field in India with stock-tank oil initially in place (STOIIP) of more than 1 billion bbl of waxy and moderately viscous crude. Aqueous-based chemical enhanced oil recovery (EOR) has been identified as the most suitable technique to improve recovery over waterflooding. The objective of the complete paper is to describe alkaline/surfactant/polymer (ASP) formulation development for Mangala, which involved more than 30 corefloods at the time of writing, with formulation design changing over time. Field Background The Mangala field has been regarded as an excellent chemical EOR candidate since its discovery in 2004. The main reservoir unit is divided into the Lower and Upper Fatehgarh formations. These units are subdivided into five reservoir units, FM1 to FM5 from top to bottom. Mangala contains waxy sweet crude oil with gravity ranging from 20 °API near the oil/water contact to 28 °API in the oil column. The crude has in-situ viscosity of 9–17 cp. The crude has good napthenic acid content and reacts with alkali to produce in-situ soap. Immediately after the field’s appraisal stage, work to identify the most suitable EOR process began. First, a polymerflooding pilot was conducted during 2011–12. The encouraging results led to full-field polymerflooding implementation in November 2014. The ASP pilot performed well; incremental oil recovery over polymerflooding was estimated to be in the range of 20–25% of the pilot STOIIP. The initial development plan involved implementing a hot waterflooding production startup to maintain reservoir pressure and effective sweep. The Upper Fatehgarh FM1 and FM2 units were developed with inverted nine-spot patterns, while the more-homogeneous lower Fatehgarh (FM3 and FM4) were developed with downdip injectors and updip horizontal producers. The Mangala field began producing under a hot waterflood in 2009, with the injected water heated to approximately 80–85°C to avoid wax deposition. Injection was started within a few months of first production. At the time of writing, the field is under polymerflooding, with results largely in line with expectations. The field, which has already produced approximately 37% of the STOIIP, is on a declining production trend, and large-scale ASP flooding is being considered as the next development initiative to arrest production decline and increase overall recovery. The complete paper discusses EOR screening studies; ASP formulations, including the initial formulation; the method adopted for selection of chemical suppliers for the pilot test; optimization of ASP formulations tested in the pilot; validation of the developed formulation to other layers of the field; and planned quality-control processes to be used during procurement of chemicals for larger applications of ASP floods in the field. This synopsis concentrates on the last three of these factors, rather than the formulations considered, which, in addition to the initial formulation, included the following: - Formula 2: ASP formulation with a sacrificial surfactant - Formula 3: ASP formulation with a single surfactant - Formula 4: Formulation with a highly hydrophilic, large-hydrophobe surfactant

Hydrogeochemistry of productive Lower Jurassic deposits of the Talinskoye oil field in Western Siberia

The aim of the study is to determine, in terms of the prevalence of influence of natural or technogenic factors, the factors of formation of the hydrogeochemical composition of productive Lower Jurassic deposits of the Talinskoye oil field. During the study, the authors of the article evaluated the effects of sedimentogenesis, elutriation, neotectonic processes and oilfield water injection on the chemical composition of the waters studied. Water injection is known to cause changes in the hydrogeochemical balance and the formation of technogenic hydrogeological systems. Formation water salinities currently range from 3.7 to 15.3 g/dm3. More than 8960.3 thou-sand m3 of water was injected from overlying sediments into productive formations to maintain reservoir pressure (2014-2021). The authors analysed the genetic coefficients of different types of water (including injected water). Then they compared the coefficients. It was concluded that injected water currently doesn't have a significant impact on the hydrogeochemical appearance of the productive Lower Jurassic reservoirs of the Talinskoye oil field.

Numerical approach on production optimization of high water-cut well via advanced completion management using flow control valves

With the development of smart downhole control devices, such as the electric flow control valve (FCV), research on completion optimization using FCV control is gaining traction for successful field production management. Applying and verifying its applicability to actual assets with uncertain production issues occur are important. This study focuses on managing downhole devices to optimize fluid production in an actual onshore oil field in Alberta, Canada. The target field has been in production operation for over 20 years, and water flooding was used in the early stages of production to maintain reservoir pressure. However, according to the flow characteristics of the field, water injection caused a high water-cut issue due to water channeling. To mitigate the problem, proactive and reactive strategies were investigated to optimize FCV control. Additionally, the effect of completion optimization was estimated considering both the field-level economic value and the fluid production behavior at the device level. In most optimization cases, the cumulative water production could be reduced compared with the base case without valve control. Notably, the flow-balancing strategy increased the revenue of the target field by approximately 23 MM$ by maximizing oil production and suppressing water production. However, reactive and streamline-balancing strategies, which directly control and delay water production, undermined the economic value due to the decrease in oil production. The findings imply that FCV control strategy of suppressing only water production for the field with high water-cut could not be the optimal solution considering the reduction in oil production and the field’s revenue. The results of this study could be used as a reference to optimize downhole devices when applying water flooding in fields where high water-cut is expected.