Injection Wells Research Articles

Application of separate layer water injection in high differential pressure wells

With the development of a heavy fine-RRB-layering system and dynamic adjustment, the number of large differential pressure wells increases gradually. The effect of high-pressure difference wells on water injection development is that it is difficult to separate water injection allocation, low pass rate of layers and short effective period of separate sealing, which affects the development effect of water flooding. For this reason, the research on stratified water injection technology with large pressure differences is carried out using step-by-step throttling. The throttling pressure difference borne by the water nozzle is reduced. The large throttling pressure difference produced by the water nozzle is realized. The qualified rate of the layer section is increased to improve the anti-creep performance of the expansion Packer and the sealing effect of large pressure difference injection wells and to extend the service life of the Packer. The field application results of 216 wells in the Shengli Oil Field show that the technique can effectively improve the pass rate of the layers and the sealing effect of the layers and prolong the life of the string.

Research on the timing of polymer flooding oil and water well fracturing

Fracturing technology is the main measure to increase production and injection in oilfield production. With the gradual expansion of the scale of polymer flooding, the proportion of fractured Wells also increases year by year. How to maximize the benefits of fracturing measures has become the key technology, and the timing of fracturing is a major factor affecting the fracturing effect. By studying the fracturing time and effect of fracturing Wells in the industrial zone of polymer flooding, the optimal fracturing time of injection-production Wells is given. The fracturing time of injection Wells should be dominated by blank water drive stage and water-cut decline period. The producing Wells with low liquid production strength and low flow pressure are suitable for whole-well fracturing in water-cut decline period, and the thick-injection-thin production Wells dominated by river channels are suitable for fracturing in low-water cut period. Thin and differential Wells with differential production are suitable for fracturing during water-cut recovery period.

The methodology for calculating the apparent water absorption index from test injection data

After the oilfield enters the medium-high water content period, the treatment problem of produced water becomes more and more prominent, and the same-well injection technology can realize the oil-water separation of the produced fluid at the well. The separated water is injected back into the oil reservoir by the injection pump, while the oil-water mixture with higher oil content is lifted to the surface by the extraction pump. However, once the tampering operation is carried out on the production layer, the fluid production capacity of the layer cannot be judged, and it is impossible to determine the reasonable production allocation of the injection and recovery layer. Moreover, in the normal production process, the production tubing can not be taken out normally, so it is difficult to determine the production capacity after blocking by logging method. Therefore, it is necessary to carry out theoretical research on the production capacity of the same injection and recovery wells after tampering according to the method of reservoir engineering, so as to provide a theoretical basis for the reasonable production allocation in the field.

Research of the movement of solutions in waterless dry horizons

The movement of solutions in waterless dry layers and the influence of irrigated rock on the radius the filtration flow and the nature of its saturation were established in the paper. The liquid flow curves were constructed for various distances from the source axis. The developed methodology of non-stationary filtration mode during underground leaching determined the filtration coefficients in laminar and turbulent modes. It is necessary to take into account the physical properties of both the rock mass and the filtered leaching solutions. Research has established that the shape of the spreading of solutions in the system of interaction between the injection and discharge wells (the edge boundaries of the streamline) must be considered as a rhombus, and the spreading angle is formed depending on the degree of clogging of the pore volume.

Numerical solution of the problem of thermal effects on high-viscosity oil through a horizontal well

In this paper, the problem of developing a high-viscosity oil reservoir due to the effect of paragravity based on heating the reservoir section between the injection and production wells is considered. The thermal effect on the formation reduces the viscosity coefficient of the oil and increases the mobility of the raw material. The heat transfer equation is solved by the PSSS method. The task is solved in three stages. At the first stage, the oil reservoir is heated, at the second – its exposure, at the third - filtration.

Efficacy and Systemic Effects of a Single Deep Orbital Triamcinolone Injection for Thyroid Eye Disease.

Orbital steroid injections offer a potential therapeutic avenue for managing Thyroid Eye Disease (TED). This study aimed to assess the effectiveness and potential systemic impacts of a single deep orbital triamcinolone injection in TED patients. In a prospective investigation conducted from January 2021 to March 2023, patients diagnosed with TED were enrolled. Inclusion criteria encompassed a Clinical Activity Score (CAS) of ≥3, extraocular muscle inflammation, and upper eyelid retraction. A total of 1 mL of triamcinolone acetonide (40 mg/mL) was administered posterior to the orbital septum at both the medial and lateral aspects of both the upper and lower eyelids. Parameters, including CAS, margin-reflex distances (MRD1 and MRD2), intraocular pressure (IOP), ocular motility (Hess area ratio [HAR%]), exophthalmometry, extraocular muscle size, and blood and urinary indices, were evaluated before and at 2 and 4 weeks after a single injection. Analysis included 28 patients (23 women, 5 men; mean age (SD): 38.7 (11.1) years), representing 56 eyes. Following the injection at 4 weeks, the mean CAS and MRD1 significantly decreased by 2 points and 0.8 mm, respectively. There was a 4.5% increase in HAR%, and extraocular muscle size decreased by 4 to 15.3 mm². Neutrophil count, C-reactive protein, and thyroid antibodies significantly decreased. No severe adverse ophthalmic or systemic effects, including IOP increases or liver damage, were observed. Bilateral single orbital triamcinolone injections provided relief from TED symptoms through both direct effects on orbital soft tissue and systemic effects by decreasing antibody reactions.

Application of Artificial Intelligence in Predicting Oil Production Based on Water Injection Rate

The utilization of artificial intelligence (AI) has become imperative across various domains, including the oil and gas industry, which covers several fields, including reservoirs, drilling, and production. In oil and gas production, conventional methods, such as reservoir simulation, are used to predict the oil production rate. This simulation requires comprehensive data, so each process step takes a long time and is expensive. AI is urgently needed and can be a solution in this case. This research aims to apply AI techniques to forecast oil production rates based on water injection rates from two injection wells. Three wells are connected with a direct line drive pattern. Three different AI methods were applied, including multiple linear polynomial regression (PR), multiple linear regression (MLR), and artificial neural networks (ANN) in constructing oil production rate prediction models. Actual field data of 1180 data are used, including water injection rate data from two injection wells and oil production history data from one production well. The dataset has been split randomly into 80% training and 20% allocated for testing subsets. The training data is used to build predictive models, while the testing data is used to validate model performance. Comparative analysis selects the model with the lowest root mean square error (RMSE) and the highest R^2 test value. Results demonstrate that the ANN model achieves the smallest Root Mean Square Error (RMSE) of 0.142 and the highest R^2 test value of 16.2%, outperforming the PR and MLR methods. The ANN prediction model provides a rapid and efficient approach to estimating oil production rates.

Application of Artificial Intelligence in Predicting Oil Production Based on Water Injection Rate

The utilization of artificial intelligence (AI) has become imperative across various domains, including the oil and gas industry, which covers several fields, including reservoirs, drilling, and production. In oil and gas production, conventional methods, such as reservoir simulation, are used to predict the oil production rate. This simulation requires comprehensive data, so each process step takes a long time and is expensive. AI is urgently needed and can be a solution in this case. This research aims to apply AI techniques to forecast oil production rates based on water injection rates from two injection wells. Three wells are connected with a direct line drive pattern. Three different AI methods were applied, including multiple linear polynomial regression (PR), multiple linear regression (MLR), and artificial neural networks (ANN) in constructing oil production rate prediction models. Actual field data of 1180 data are used, including water injection rate data from two injection wells and oil production history data from one production well. The dataset has been split randomly into 80% training and 20% allocated for testing subsets. The training data is used to build predictive models, while the testing data is used to validate model performance. Comparative analysis selects the model with the lowest root mean square error (RMSE) and the highest R^2 test value. Results demonstrate that the ANN model achieves the smallest Root Mean Square Error (RMSE) of 0.142 and the highest R^2 test value of 16.2%, outperforming the PR and MLR methods. The ANN prediction model provides a rapid and efficient approach to estimating oil production rates.

Low-permeability reservoirs flooding using horizontal wells

For the first time in the practice of horizontal well flooding the study investigates the influence of horizontal well length, number of stages, and proppant loading on productivity during hydraulic development of low-permeability reservoirs using horizontal wells. To increase the sweep efficiency in systems with horizontal wells, a new development systems configuration is proposed, relying on longitudinal horizontal production wells and transverse horizontal injection wells with respect to the regional stress direction. The use of this configuration will not only increase the efficiency of reservoir pressure maintenance systems, but also reduce capital costs for well construction by reducing the injection wells to production wells ratio per development unit while maintaining system stiffness. Keywords: horizontal injection well; Auto-HF fracture; low-permeability reservoir; reservoir pressure maintenance system; oil recovery ratio increasing

Waterflooding optimization based on the CRM and solving the linear programming problem

Among the many technologies for increasing the efficiency of oil field development using waterflooding, the least economically expensive include hydrodynamic methods for increasing oil recovery, based on changing the directions of filtration flows. Thus, one of the key tasks of increasing the efficiency of waterflooding at a late stage of development is to reduce the volume of ineffective injection. The article discusses the problem of redistributing volumes of injected water between injection wells for a given total injection volume in order to increase oil production. An analytical relationship is proposed for assessing injection efficiency, based on known displacement characteristics and calculated well interference coefficients based on CRMP. The optimization problem is formulated as a linear programming problem. Using the example of a fragment of an oil deposit, the possibility of assessing the injectivity of injection wells is shown, which makes it possible to increase the predicted oil production by changing the direction of filtration flows in the formation. As a result of applying the developed algorithm, the predicted increase in cumulative oil production amounted to 19683 m³ (9.5%) over 15 years. Keywords: waterflooding optimization; capacitive-resistive model; CRM; linear programming; injection efficiency; interwell connectivity.

Introduction of Wireless Pressure Wave Intelligence Technology in Water Injection Wells of Offshore Oilfields

Introduction of Wireless Pressure Wave Intelligence Technology in Water Injection Wells of Offshore Oilfields

The Exergy and Energy Analysis of Change Phase Steam in Patuha Geothermal Well Production

A Geothermal Power Plant Company in West Java Indonesia have capacity around 55MW. It company have increased the well production quality to keep up the Indonesia's energy demands. The power plant has been operated around ten years, it has ten geothermal production wells and two injection wells. The either of it wells has an abnormality. It wells has water dominated condition so, the separator equipment is required to separate the steam from water and vapor. Previous study indicated that subsurface water entering the broken reservoir pipe. That leaks in reservoir pipe was repaired in 2020. The impact after the pipe have been repaired it made the fluid characteristic of reservoir be vapor dominated. After that a separator as a steam separator is no longer required. The study compares the value energy and exergy power of the power plant. The calculations are performed from the well reservoir and all power plant equipment. According to the results of the energy study, the plant's energy efficiency after the transformation increased by 0.03%, from 19.48% to 19.52%. The exergy value of the brine in either wells (separated steam cycle) is also known to be 2.512,52 kW, beyond which the value will become zero.

Modeling of well performance during oil reservoir development on the elastic-water-drive mode using regression analysis

One of the important tasks of analyzing oil field development is predicting well performance. For this purpose, displacement characteristics are often used, which represent the dependence of some indicators on others. To determine the parameters of these dependencies, regression analysis of historical data is used. Dependences of the choice of watering production wells with water pumped into injection wells, water or the law of the exhausted aquifer. A feature of displacement characteristics is generally considered to be that they can only be used when fluid flows in the formation are established. This is due to the fact that with the classical approach, displacement of characteristics is not observed in the explicit form of well interference. Therefore, the search for displacement characteristics, with the help of which we can talk about the mutual influence of wells, is an important factor. This is the subject of this work. Water cut and water-oil ratio (WOR) are related by a well-known formula. The paper proposes regression models for WOR. They obtained the result taking into account the classical logic of the WOR from accumulated oil production. Water cut is calculated from water saturation. The proposed regression models of water saturation are based on the analysis of equations of theories of two-phase filtration in difference form. 11 watering models were studied, two including classical ones and 9 new ones. Dependencies for reservoir and bottomhole pressures were also developed. The proposed models are intended to analyze the operation of wells during the development of an oil reservoir in an elastic-water-pressure mode. The models were tested on a real field and their effectiveness was analyzed. Some new models perform well in a selection of tests. In particular, all the proposed models give better results than the classical model: the logarithm of the water-oil ratio from the accumulation of oil production.

Determination of the optimal working time of injection wells of an oil reservoir using hydrodynamic modeling

Determination of the optimal working time of injection wells of an oil reservoir using hydrodynamic modeling

PROSPECTS FOR INFILL DRILLING OF WELLS AT A LATE STAGE OF DEVELOPMENT ON THE EXAMPLE OF THE BS10 OBJECT OF THE MAMONTOVSKOYE FIELD

The article is devoted to the issue of optimizing the development system and increasing the efficiency of reserve production at the late stage of development of the BS10 object of the Mamontovskoye field and the formation of a strategy for its additional development. The results of the analysis of actual data from drilling horizontal wells and sidetracks made it possible to identify the most significant criteria for determining reserve localization zones for the purpose of placing new wells. The main factors for the effective placement of horizontal wells include: local dome uplifts, clinoform boundaries — zones where clinoforms pinch out, edge zones — zones with a lack of stock that require further exploration, distance from the formation pressure maintenance system — away from existing injection wells and with high accumulated injection , dissected zones, «pinched undeveloped reserves» — between injection rows, areas with long-term downtime of both injection and production wells — effects of reserve relaxation. The actual results of studies of core material and carbon-oxygen logging indicate the presence of relaxation processes in the formations of the BS10 object and the localization of oil pillars in the top part of the formation, which is further confirmed by hydrodynamic modeling. One of the key factors for planning the most effective measures is to take into account the effects of segregation and relaxation of stocks. The results of the implementation of infill horizontal drilling confirmed the high efficiency in areas of localization of current recoverable reserves in order to increase the rate of their production and achieve the approved values of oil recovery factors, the correct choice of the development strategy for the object at the current stage. The proposed methodological approach has shown high efficiency in searching for potential sites for drilling infill wells.

ABOUT SOME PROBLEMS OF WATERFLOODING IN CARBONATE RESERVOIRS

The features of waterflooding of carbonate (fractured-porous) rocks, caused by the interaction of the system of fractures with the matrix (blocks) of the rock, are considered. It is shown that the slower propagation of the pressure pulse in the rock matrix in comparison with the propagation of this pulse along the fracture system of the formation leads to compression of the rock blocks in the near-wellbore zone of the injection well, as a result of which stress concentration occurs at the ends of vertical fractures, which increases the likelihood of these fractures growing into the roof of the productive formation. It is shown that in order to prevent the development of this process, the growth rate of water injection pressure should be limited in accordance with the time of liquid pressure equalization in the pore space of the rock matrix and in the fracture system. When developing production wells drilled in fractured porous media, in order to prevent the development of the process of closing fractures in the bottomhole zones of these wells, the drawdown reduction rate must also be limited in a similar way. It is noted that when applying technologies for non-stationary flooding of productive reservoirs, the main factor determining their effectiveness is the change in the direction of filtration flows in the reservoir. This leads to the activation of filtration processes in the stagnant zones of the formation and the intensification of the processes of capillary impregnation of low-permeability interlayers with water from more flooded highpermeability interlayers.At the same time, it is important to take into account that when changing the direction of filtration flows at a late stage of development of carbonate reservoirs, in order to prevent reimpregnation of hydrophobic rock blocks with oil, it is more expedient to change the operating modes of production rather than injection wells. It is shown that water flooding of hydrophobic carbonate reservoirs results in incomplete water displacement of oil as a wetting phase from rock blocks. To reduce the residual oil saturation of rock blocks, it is advisable to increase the displacement pressure gradient in the reservoir in combination with a change in the direction of filtration flows in it.

Optimizing the wells location using the Metaheuristic algorithms, as well as optimizing the drilling time of production and injection wells in one of the reservoirs in south west of Iran

Optimizing the wells location using the Metaheuristic algorithms, as well as optimizing the drilling time of production and injection wells in one of the reservoirs in south west of Iran

APPLICATION OF HYDROGELS FOR CONFORMANCE CONTROL AND FLOW DIVERSION

The use of hydrogels in the development of oil fields by the flooding method has firmly established itself in the oil industry, and this direction is constantly evolving in all oil-producing countries around the world, as evidenced by the growth of publication and patent activity on this topic. Operations for conformance control and flow diversion are impossible to imagine without the use of gel technologies today. Inorganic, organic, and hybrid gels, as well as foam gels, gel-forming and gel-dispersed systems are used.The ability to widely regulate structural-mechanical properties, thermal stability, and shear resistance through the introduction of micro- and nano-sized additives has made hydrogels indispensable tools for petroleum engineers.In this review, modern trends in the use of hydrogels for flow diversion from injection wells are identified, and the most promising directions are explored in light of depleted reservoirs and deterioration in the structure of oil reserves. Geological prerequisites for using hydrogels for flow diversion during field development are discussed, including hydrogels based on a range of acrylamide polymers, sedimentary-gel-forming and gel-dispersed compositions, as well as gels based on inorganic compounds.Various gel-forming compositions based on water-soluble and waterswelling polymers, as well as silicon and aluminum-based inorganic compounds, are used for flow diversion and conformance control. Combining gels with dispersed materials and sedimentary compositions allows for the strengthening of the structural-mechanical properties of the flow-diverting system, making it possible to apply these compositions in fractured-porous collectors. The ability to regulate the gelforming time allows for placement of the gel screen at a specified distance from the injection wellbore. This approach has firmly established itself in industrial practice and continues to be improved in terms of reducing the cost of used compositions and increasing their effectiveness.

CALCULATION OF AN ALTERNATIVE DEVELOPMENT SYSTEM FOR THE MAIN DEPOSIT OF THE DANILOVSKOYE OIL AND GAS CONDENSATE FIELD

The article provides a calculation of an alternative development system for deposit 3 (Main deposit ) of the Danilovskoye oil and gas condensate field. At the time of the analysis, this deposit is in the pilot development stage, with six development variants proposed in the trial operation project, which assume a principled arrangement of wells along an areal homogeneous grid. At the same time, due to the need to maintain the energy of the formation (that is, certain values of thermodynamic conditions), three provide for a transition to pressure maintenance, with the resulting four-point scheme of effect on the deposit (intensity 1:2; one well for injection, two for production). In the alternative model under consideration, the development method also involves a subsequent transition to pressure maintenance, but with a more active, five-point waterflooding system (intensity 1:1, equal ratio of production and injection wells), if necessary, as will be shown in the work, easily convertible to a nine-point one. The latter is an objective advantage, since the formation has low permeability and high vertical and lateral heterogeneity, and during waterflooding, zones not affected by the impact may appear, and, consequently, zones with high residual oil saturation. When calculating the characteristics of the proposed alternative method, modeling using the Peaceman method is used. Peaceman’s method is based on determining the well-reservoir connectivity of each individually opened cell, used to calculate flow rates (taking into account different values of average water cut for wells). The method is classical and, although it includes a large number of limiting assumptions, it is applicable everywhere and can provide sufficient justification for the effectiveness of the chosen development variant. General recommendations for the development of the entire field are also given (taking into account the low viscosity and lightness of oil and the properties of reservoir rocks). Such as the use of acid fracturing technology, the use of surfactants, hydrochloric acid treatments (HAT) and a complexing phosphorus-containing reagent — AFC.

FLUID FLOW CONTROL IN POROUS MEDIA WITH CONSIDERATION OF ELECTROKINETIC EFFECTS

The paper presents results of the research on the influence of electrokinetic characteristics of fluids on its flow in porous media. Experimental studies have shown the effect of fluid slippage in the channels of porous media due to the electrically charged boundary "liquid-porous medium". It is shown that the change of flow velocity profile and pressure gradient is caused by the display of electrokinetic effects in the filtration of polar liquids.The investigation has shown that the process of the electrolyte solutions filtration in a porous medium is accompanied by the change in the liquid flow rate and the electro-potential of the flow. The periodic nature of changes in flow characteristics is explained by continuous charge formation and charge interaction in the diffuse layer. Periodic charge accumulation and subsequent charge transfer across the channel cross section depending on the charge sign acquired, as well as compression of the diffuse layer with increasing NaCl electrolyte concentration in aqueous solution may be the cause of fluid flow variations. The observed effects may serve as a tool for controlling fluid flow in water-oil-saturated formations and, in particular, injectivity of injection wells by controlling electrical conductivity of water injected into the formation.