Increasing Water Cut Research Articles

Optimization procedure for conformance control

The article is devoted to the development of an optimization procedure for conformance control treatment. Currently, due to the significant share of reservoirs with high water cut, it is relevant to use methods that allow reducing the rate of production water cut increase. One of the most common methods to do this is to improve conformance by injecting suspension into the reservoir. The classical model of deep bed suspension migration has shown itself well for calculating the technological parameters of treatment, but it does not contain criteria for optimizing the process. The introduction of such criteria and their physical justification is the purpose of this work. The following objectives were set: modification of the classical model of deep bed suspension migration for layered strata, introduction of criteria of suspension treatment efficiency, and optimization of the process. Mathematical model consists of mass conservation laws and Darcy’s law. Initial data were selected for one of the fields in West Siberia, where suspension treatments were carried out to improve conformance. The field experience of these treatments is analyzed, the wells where the treatment was successful are determined. The new criterion for the effectiveness of suspension treatment is introduced. This criterion is the difference in the standard deviations of the flow rate along the layers before and after the treatment. It is established that this difference more clearly demonstrates the injectivity profile exchange than the classical Dykstra-Parsons criterion. The optimization procedure allows assessing the required slug volume that provides the maximum injectivity profile redistribution.

Study on the channeling limit of polymer flooding in the conglomerate reservoir

The conglomerate reservoirs are known for their high degree of heterogeneity, which poses a challenge during polymer injection. Fluids tend to channel along dominant paths leading to premature appearance of polymer in the oil well. This phenomenon results in a rapid increase in water cut, leading to wastage of the polymer. Currently, there is no reliable method for identifying polymer channeling in such conglomerate reservoirs. To address this issue, this paper conducts physical simulation experiments on parallel cores under varying heterogeneous conditions based on the geological characteristics of the reservoir. The study analyzed and statistically evaluated the distribution ratio, water cut, and polymer concentration in the output under varying heterogeneous conditions. This analysis identified the distribution ratio and polymer concentration as key indicators of polymer channeling. Based on these findings, a comprehensive discriminant diagram of polymer channeling was established. The study found that the coefficient of permeability variation (CV) was the primary factor contributing to channeling. This diagram can be used to understand the underlying principles of polymer channeling and provide technical guidance for developing effective profile control schemes and optimizing site construction strategies.

Quartz Hydrolysis Analysis of Pure Quartz for Enhanced Oil Production; Influence of Time, pH, and Salinity on Hydrolysis

The issue of sand production in reservoirs has been recognized as a critical problem in oil and gas fields for several years due to its numerous negative impacts on oil and gas production. Sand production from wells can damage both surface and subsurface equipment, reduce well productivity, and negatively impact the oil production economy. Oil production challenges arise when sand production increases as the water cut increases. Several factors have been associated with this phenomenon, with the most critical factor being silica dissolution - a chemical reaction between quartz and water that decreases formation strength. This study explores the dissolution of silica on pure quartz and the effects of added electrolyte (NaCl, CaCl2, MgCl2, and KCl) concentration, temperature, and pH on the dissolution process. The concentration of silica dissolved in solution was measured using UV-Vis spectrophotometry to determine the dissolution of silica on quartz. The results outcome indicate that the rate of silica dissolution is significantly influenced by variations in temperature and alterations in pH levels. The salinity conditions exhibit minimal alterations in comparison to distilled water. The highest concentration of silica dissolved in a solution has been seen at pH levels of 12 and 3, with concentrations of 118 mg/l and 68 mg/l, respectively. In terms of temperature, it was observed that there was an increase in the dissolution of silica from 30°C to 90°C, ranging from around 170% to 600%. Regarding salinity, it can be shown that NaCl and KCl exhibit the most significant impact on silica dissolution when compared to other brine solutions, with concentrations of 45 and 49 mg/l, respectively. The study claims that the formation strength may be influenced by water quality through the processes aimed at stimulating or lowering silica dissolution. Therefore, the optimal water quality design for water injection is paramount in mitigating sand production challenges.

Measurement of high water-cut heavy oil flow based on differential pressure of swirling flow

Real-time measurement of heavy oil production is critical to ensure stable production. Due to the complex kinematic characteristics of heavy oil, existing methods cannot accurately measure its flow rate and water cut. In this paper, a novel method is proposed to measure the high water-cut heavy oil flow by using the differential pressure of the two-phase swirling flow in the pipe. For the swirling flow in the pipe, the radial differential pressure and the axial differential pressure exist simultaneously, which are very sensitive to the flow rate and water cut. The formation mechanism of the two kinds of differential pressure is analyzed theoretically, and their relationship with flow rate and water cut is studied by experiment and numerical simulation. The measurement model of heavy oil–water two-phase flow on the above relations is validated by field experiments. The radial differential pressure is only related to the two-phase flow rate, varying exponentially with the flow rate when the oil viscosity is greater than 10 000 mPa s. This characteristic is very useful for the heavy oil–water two-phase flow measurement. The axial differential pressure decreases with the increase in water cut in cases of water cut <85%, while it increases with the water cut in cases of water cut >85%. With the increase in water cut, the ratio of axial differential pressure to radial differential pressure first decreases and then increases. The relative errors of the established measurement model for flow rate and water cut are 0.19%–17.92% and 0.21%–15.5%, respectively, and more than 70% of the measurements with a relative error of less than 10%. The study of the heavy oil–water two-phase flow measurement method can optimize the measurement cost and accelerate the process of intelligent oilfield construction.

Evaluation of the development effect of polydynamic drive in Class IIB oil reservoir of Lamadian Oilfield

With the continuous deepening of oilfield development, the target of oilfield development is gradually shifting towards reservoirs with poor physical properties, and polymer flooding can better utilize such reservoirs.The heterogeneity of Class II B oil layer in Lamadian Oilfield is severe, and polymer flooding takes effect later, with a small decrease in watercut.A study was conducted on the evaluation of polymer flooding development effectiveness for Class II B oil layers through reservoir numerical simulation . Research has shown that when the initial watercut is constant, a lower injection pressure can increase the utilization degree of remaining oil in the middle and high permeability layers of Class II B oil layers. With the increase of injection pressure, the response time is shortened, and the decrease in watercut is reduced; As the watercut increases, the injection pressure should gradually increase in order to improve the recovery of low permeability reservoirs;As the watercut increases, the injection pressure should gradually increase in order to improve the recovery of low permeability oil layers;At a watercut of 95% and injection pressure of 7MPa, a field experiment was conducted with a molecular weight polymer of 12 million , and the response time was 6 months. The cumulative oil increase was 14675m3, achieving good polymer flooding effect.

ПОВЫШЕНИЕ ЭФФЕКТИВНОСТИ ЭКСПЛУАТАЦИИ ЯРАКТИНСКОГО МЕСТОРОЖДЕНИЯ С ПРИМЕНЕНИЕМ ВЫРАВНИВАНИЯ ПРОФИЛЯ ПРИЕМИСТОСТИ НА ОСНОВЕ БИОПОЛИМЕРОВ

Integrated within the territorial boundaries of the Irkutsk region, the Yaraktinskoye hydrocarbon field is one of the key assets in the field of crude oil production and has been subject to active extraction procedures since the 1970s. This field is characterized by limited permeability parameters and heterogeneous properties of oil-bearing formations, which makes effective extraction of hydrocarbons highly difficult. Traditionally, to optimize the oil recovery factor at similar facilities, the permeability profile leveling methodology is used. It has been established that the effectiveness of this approach is significantly limited by geological and structural characteristics. Consequently, there is an urgent need to develop more effective mechanisms to increase the operational efficiency of the Yaraktinskoye field. At the moment, the field is facing many problems from an operational point of view, including a decrease in the oil recovery factor due to limited permeability of the formations and high water cut. The permeability profile of injection wells is also not homogeneous enough, which further exaggerates the problem of oil recovery. These factors collectively led to inflation of operating costs and degradation of the economic efficiency of the operating process. As part of solving the existing problems facing the Yaraktinskoye field, research was carried out on the efficiency of development using enhanced oil recovery technologies based on xanthan compositions in order to optimize the permeability profile of injection wells. Research is aimed at expanding the application capabilities of biopolymers in a wider range of geological and structural conditions. The research results indicate a significant optimization of the method for correcting the permeability profile, which in turn helps to increase oil recovery by 12-15% and reduce operating costs by 2025%. The research results may be useful for further exploitation of the field under conditions of increased water cut.

Flowback Characteristics Analysis and Rational Strategy Optimization for Tight Oil Fractured Horizontal Well Pattern in Mahu Sag

With the deep development of tight reservoir in Mahu Sag, the trend of rising water cut during flowback concerns engineers, and its control mechanism is not yet clear. For this purpose, the integrated numerical model of horizontal well pattern from fracturing to production was established, and its applicability has been demonstrated. Then the flowback performance from child wells to parent wells and single well to well pattern was simulated, and the optimization method of reasonable flowback strategy was discussed. The results show that the formation pressure coefficient decreases as well patterns were put into production year by year, so that the seepage driving force of the matrix is weakened. The pressure-sensitive reservoir is also accompanied by the decrease of permeability, resulting in the increase of seepage resistance, which is the key factor causing the prolongation of flowback period. With the synchronous fracturing mode of well patterns, the stimulated reservoir volume (SRV) is greatly increased compared with that of single well, which improves the reservoir recovery. However, when the well spacing is less than 200 m, well interference is easy to occur, resulting in the rapid entry and outflow of fracturing fluid, and the increased water cut during flowback. Additionally, the well patterns in target reservoir should adopt a drawdown management after fracturing, with an aggressive flowback in the early stage and a slow flowback in the middle and late stage. With pressure depletion in different development stages, the pressure drop rate should be further slowed down to ensure stable liquid supply from matrix. This research can provide a theoretical guidance for optimizing the flowback strategy of tight oil wells in Mahu sag.

THERMAL FIELD IN A HORIZONTAL WELL APPLIED TO THE DETERMINATION OF FLUID FLOW BY ACTIVE THERMOMETRY

Today, in the context of falling oil production and increasing water cut, the importance of geophysical control over field development is increasing. A promising method of production logging is active thermometry, it is based on the creation of a thermal disturbance area in the wellbore, for example, due to induction heating of a section of a metal pipe (liner or casing, depending on the design of the well). As a result of heat exchange with a locally heated pipe section, heat marks are formed in the liquid, moving along the wellbore. The article presents the results of physical modeling of thermal processes during local induction heating of a section of a horizontal well. It has been experimentally established that with an induction heater power of about 1 kW and flow rates in the pipe up to 50 m3/day, the heating of the pipe wall reaches 12 K. As part of the experimental studies, the movement of heat marks was monitored using two modules of temperature sensors distributed over the pipe cross section. It is shown that the nature of temperature change in time is determined by the position of the temperature sensor in the pipe section. The greatest thermal anomalies are noted for sensors pressed against the pipe in its upper part, the smallest - for sensors located in the lower part of the pipe. The fluid flow rate in the pipe was estimated from the rate of passage of the heat mark between the temperature modules. It is shown that the calculated flow rate is overestimated relative to the actual one due to the influence of natural thermal convection, which causes the occurrence of a natural convective fluid flow in addition to the forced movement with a given flow rate. A new analytical solution has been obtained for calculating the dynamics of the pipe temperature in the induction heating section, a comparison of the results of calculations using the analytical model with the experimental results showed good agreement. The results of experimental studies can be used in interpreting the results of field logging wells using active thermometry, in particular, the sensitivity of the pipe temperature in the induction heating section to the flow rate can be used to solve inverse problems of estimating the flow rate in a pipe by measuring its surface temperature using the obtained analytical solution.

Failure Analysis of Corrosion and Fracture of P110 Tubing in a Development Well

In this paper, a fractured and corroded tubing string was analyzed through macroscopic observation, chemical composition analysis, metallographic and mechanical test. The corrosion products were studied by SEM, EDS, and XRD method. The results showed that the corrosion of tubing in this well was caused by CO2 corrosion, the well contains CO2 medium and increasing water cut in the late stage of development were the main reasons of serious corrosion, the scaling on the tubing wall aggravated the corrosion. Finally, some suggestions were proposed for avoiding or slowdown this kind of corrosion failures.

Experimental investigation on using CO2/H2O emulsion with high water cut in enhanced oil recovery

CO2 emulsions used for EOR have received a lot of interest because of its good performance on CO2 mobility reduction. However, most of them have been focusing on the high quality CO2 emulsion (high CO2 fraction), while CO2 emulsion with high water cut has been rarely researched. In this paper, we carried out a comprehensive experimental study of using high water cut CO2/H2O emulsion for enhancing oil recovery. Firstly, a nonionic surfactant, alkyl glycosides (APG), was selected to stabilize CO2/H2O emulsion, and the corresponding morphology and stability were evaluated with a transparent PVT cell. Subsequently, plugging capacity and apparent viscosity of CO2/H2O emulsion were measured systematically by a sand pack displacement apparatus connected with a 1.95-m long capillary tube. Furthermore, a high water cut (40 vol%) CO2/H2O emulsion was selected for flooding experiments in a long sand pack and a core sample, and the oil recovery, the rate of oil recovery, and the pressure gradients were analyzed. The results indicated that APG had a good performance on emulsifying and stabilizing CO2 emulsion. An inversion from H2O/CO2 emulsion to CO2/H2O emulsion with the increase in water cut was confirmed. CO2/H2O emulsions with lower water cuts presented higher apparent viscosity, while the optimal plugging capacity of CO2/H2O emulsion occurred at a certain water cut. Eventually, the displacement using CO2/H2O emulsion provided 18.98% and 13.36% additional oil recovery than that using pure CO2 in long sand pack and core tests, respectively. This work may provide guidelines for EOR using CO2 emulsions with high water cut.

Study On Fine Injection and Production in the Infill Well Area of A Transition Belt

A transition belt of Daqing oilfield was put into operation in July 2019. The injection and production perfection degree of some well groups is low, the injection-production ratio is unbalanced, the formation energy is insufficient, the yield declines greatly, and the water cut rises quickly.In order to slow down the decline of the block and control the rising speed of water cut, the actual problems existing in the block are discussed. By drawing on the successful adjustment practice of the infill well area of the transitional belt in the B transition belt, the injection and production status and adjustment methods of the infill well area in the transitional belt in A transition belt were studied, two aspects of injection-production system and injection-production structure in block are considered. Different adjustment countermeasures were formulated for oil and water Wells in different strips, and the direction of fine injection and production adjustment was clarified. By using the well focus, structure adjustment and water injection production structure adjustment and so on, effectively reduce the block production decline, control water cut increase speed, and reduce the contradiction between the layers. To realize the purpose of further increase the level of reservoir utilization and improve the development level of A transition belt. At the same time, it provides experience for the injection and production adjustment of the infill well area for the future transition zone.

ANALYSIS OF HYDRODYNAMIC INTERACTION OF WELLS BASED ON DETERMINATION OF PRODUCTION AND INJECTION COMPENSATION BALANCE USING THE EXAMPLE OF RESERVOIR — BARREM CLINOFORM OF PRIOBSKY SEDIMENTATION BASIN

Abstract. Long-term development of oil fields using a reservoirpressure maintenance system by injecting water into the formation leadsto a number of features of well operation identified during fieldgeophysical and hydrodynamic studies. The combination and processingof parameters characterizing the field development indicators and theoperation of wells in the injection-production section make it possible toconduct a qualitative assessment of the processes occurring in the subsoil.The article describes the procedure for determining possible sources ofwater flooding of oil wells in a large multi-zone field in Western Siberia.In order to determine the compensatory balance of production andinjection taking into account the regional stress characteristic of the field,calculations were made using a geometric figure in the form of an ellipse.The drainage zone described in this way does not contradict the ratio ofthe number of injection and oil wells in the nine-point developmentsystem. The analysis of geological and field information and hydrodynamicstudies made it possible to identify a difference in the signs of increasedwater cut of the product with uncontrolled growth of a man-made fracturein the direction of regional stress and when overlying horizons, which areinterbedded with water-saturated sandy bodies formed under the Bystrinskyclay pack during the regression cycle of sedimentation, were included inthe development. From the point of view of the analysis results, one of thepossible reasons for the development of man-made fluid contacts betweenthe injected and formation water of the overlying formation is a violationof the cement support behind the production string of the injection well.And as a result, there is a top-down flow in the production wells. Theoccurrence of disturbances in the cement support is a technical reason andcan be associated with technological processes carried out on injectionwells during operation, or imperfection in adhesion during insulation andtechnical work. The methods used in the article to determine thehydrodynamic interaction of wells and the signs of formation ofinterformation fluid contacts made it possible to assess the possiblereasons for the increase in water cut in the complex, low-permeability oilreservoirs of the Goteriv-Barremian clinoform of the Priobskysedimentation basin.

Microscopic gas displacement efficiency of enhanced gas recovery in carbonate gas reservoirs with edge and bottom water

Carbonate gas reservoirs with edge and bottom water contain abundant reserves, making them key production targets in the Tarim Basin, Sichuan Basin, Ordos Basin, and other petroleum provinces. Water invasion may occur in the middle and late development stages of such reservoirs, leading to reduction of gas displacement efficiency and gas recovery. In this paper, a pore-scale water-gas immiscible flow model is established by coupling the fluid flow equation and the gas-water contact (GWC) tracking equation. The process of gas displacement with water is simulated in the heterogeneous porous media generated by the quartet structure generation set (QSGS). Finally, the mechanisms of remaining gas distribution and formation are analyzed, and the variation mechanism of microscopic gas displacement efficiency is discussed. The results are obtained in three aspects. First, the remaining gas is distributed at the blind end, in the pore-throat and as clusters, with their proportions and scales jointly controlled by microscopic pore structures, wettability and capillary number. The remaining gas can be further produced by changing the production pressure differential to disturb the original pressure system and gas expansion, so as to improve the microscopic gas displacement efficiency. Second, the microscopic gas displacement efficiency is closely related to the gas flow process. Formation or expansion of each water flow path may cause rapid increase of water cut and slows down the increase of gas displacement efficiency. Third, the microscopic pore structure and wettability are the inherent features of the gas reservoir, so the capillary number can be optimized to change the mode of GWC advancement, and then to effectively improve the microscopic gas displacement efficiency. It is concluded that for real gas wells, the evolution of mechanical mechanisms of GWC advancement should be revealed depending upon the microscopic pore structure and wettability of the reservoir, and then the optimal capillary number can be determined. Furthermore, clarifying the pore-scale water-gas flow characteristics and physical mechanism of microscopic gas displacement provides guidance for the planning of enhanced gas recovery.

Performance evaluation of downhole oil–water separators in wells that use DWL technique using computational fluid dynamics: influence of velocities and flow rates

A major issue in many oil fields is the production of undesirable water from oil wells. One of the most important causes of unwanted water is water coning. This phenomenon may be leading to a decreasing oil production rate, an increasing water cut, and consequently high production costs. Downhole water loop (DWL) is a relatively new and effective technique to control water coning. Even though many studies have shown how effective the DWL approach is in reducing the problem of water cones, the issue of oil droplets escaping the drainage zone might damage the injection area and perhaps cause blockage. It is suggested to use the downhole oil–water separator (DOWS) approach to separate oil droplets from the water stream based on the difference in densities. This article gives a numerical analysis of DOWS in two stages. In order to confirm that the simulator could faithfully simulate this sort of separator, the findings of the employed simulator were first compared with the preceding analytical solutions. Then the impact of inlet velocities and flow rates was discussed numerically for seven scenarios in the second stage. The results showed that a high inlet velocity encourages the formation of oil droplets as a result of the mixture stream colliding with the separator walls, whereas a low inlet velocity produced undesirable results because the oil droplets remained dispersed in the water stream (the separation efficiency was 30.6% less than the high-velocity condition). In the following case, a novel design based on expanding the mixture input area and changing the mixture inlet and outlet points was presented to lessen the impact of mixture inlet velocity. The separation efficiency was improved by 38.65% as a result of this approach. Finally, the discussion's findings about the effect of mixture flow rates at the separator's inlet and upper outlet showed that the inlet rate has a bigger impact on separator performance than the upper outlet rate. The outcomes of this research and the numerical models can be utilized to enhance the system-level design, better understand this kind of separator, and increase its efficacy.

Economic Evaluation Of Water Production Management With Rpm (Relative Permability Modifier) Treatment Based On Gross Split Contract In “Re” Well In “Dn" Field

The "RE" well in the "DN" field is an oil well produced in June 2004 with an initial water cut value of 15% as time went on there was a fairly high increase in the water cut value reaching 97% which means that it caused increased water production. and oil production decreased from 387 BOPD to 11 BOPD.
 Appropriate handling in overcoming excessive water production, one of which is by using a method that can selectively restrain water production without restraining hydrocarbon production with RPM (Relative Permeability Modifier) ​​Treatment. RPM (Relative Permeability Modifier) ​​is a type of polymer with a high molecular weight as the main molecule of RPM. RPM can be done without isolating the layer zone so that it can be injected bullhead into all layer zones to reduce water permeability.
 This final project research has been seen from increasing the rate of oil production and decreasing the water cut. The selected well is the "RE" well in the "DN" field which has an increasing water cut value and decreased oil production. Then calculate the economy using the gross split method to calculate the feasibility level of the RPM (Relative Permeability Modifier) ​​Treatment project.

Productivity Analysis of Fractured Horizontal Wells in Tight Gas Reservoirs Using a Gas–Water Two-Phase Flow Model with Consideration of a Threshold Pressure Gradient

Tight gas reservoirs are valuable yet challenging unconventional resources as a result of their complex flow mechanisms. Typical challenges are characterized by gas–water two-phase flows with a threshold pressure gradient (TPG). In this work, experimental studies are initially conducted to investigate and quantify the influence of water saturation on the TPG. A gas–water two-phase flow model is then established for a fractured horizontal well considering the influence of water saturation on gas–water permeability and TPG, along with the dynamic changes in the water–gas ratio. Sensitive studies are performed to investigate the impact of various parameters on the productivity of a horizontal well. The results demonstrate that, as water saturation increases, the TPG increases and the relative permeability of the gas phase decreases, resulting in the gas well productivity decrease. As the permeability decreases, the changes in the TPG become more prominent, leading to a greater impact on productivity. In comparison to a constant TPG, the changes with water saturation in the TPG have a more significant effect on productivity. Hence, it is beneficial to regulate the rate of the water cut increase to enhance production in tight gas reservoirs.

Study on the mechanism of improved oil recovery by nitrogen foam flooding in bottom water reservoirs

There are abundant bottom water reservoirs in China. Unlike conventional oil reservoirs, bottom water reservoirs have various problems, such as early water breakthrough, short water-free oil recovery period, and rapid water cut increase. For example, during water flooding, the injected water easily breaks into the bottom water and does not effectively displace the upper crude oil. The recovery rate is generally low. Based on this phenomenon, an experimental study of nitrogen foam flooding in bottom water reservoirs is conducted in this paper. The seepage characteristics of nitrogen foam in oil and water layers are studied through one-dimensional core tube experiments. Through two-dimensional plate oil displacement experiments, we have revealed the fluid migration and distribution characteristics in the plane and vertical directions during nitrogen foam flooding in bottom water reservoirs; additionally, we have summarized the mechanisms of nitrogen foam in bottom water reservoirs involved in improving oil recovery characteristics. The research results show that the seepage resistance of foam in the water layer is much greater than that in the oil layer, effectively increasing the displacement strength of the oil layer. During the development stage of bottom water flooding in bottom water reservoirs, the water cut increases rapidly, the bottom water coning is obvious, and the residual oil is mainly distributed between the oil wells and the upper part of the oil layer near the wellbore. During nitrogen foam flooding, the foam enters the water layer to form an effective plug so that the subsequent foam is diverted into the oil layer; additionally, the oil is displaced laterally to the production well for production. When the foam enters the oil layer, it defoams and floats to form a secondary gas cap; this effect causes displacement of the residual oil at the top and effectively improves the displacement efficiency by weeping volume of the injected fluid”

TECHNOLOGY EFFICIENCY IN-SITU COMBUSTION AT THE KARAZHANBAS DEPOSIT

The evaluation of the effectiveness of the development of the Northern section of the I object of the Karazhanbas field by injecting a coolant into the reservoir is considered. To intensify oil production in hard-to-recover reserves of the field, thermal methods are considered, such as the use of hot water and steam as an injection agent into the productive reservoir, the creation of a combustion front or a high-temperature zone in the reservoir. Considering the development trend of the northern territory of the Karazhanbas field, it was found that reservoir energy is depleted, reservoir oil properties change, becoming more viscous, resulting in a rapid decrease in production rate and pressure drop, with an increase in water cut. Modeling the application of in situ combustion technology (ICG) is of practical importance in the conditions of the Karazhanbas field and will improve the efficiency of using technically possible heat carriers. An analysis of the development of the Karazhanbas field is presented, as well as the dynamics of the current and accumulated compensation for withdrawals by injection in the Northern area in recent years of development. The analysis of the presented indicators made it possible to conclude that with a decrease in the volume of steam injection into the reservoir, for the uniformity of oil production, it is necessary to consider the technology of using in-situ combustion in this area. The substantiation of the numerical method is given, which makes it possible to represent the formation of fields of pressure, temperature, saturation (oil, water and gas), concentrations of components (oxygen, water vapor and inert gas) when using in-situ combustion. Based on the qualitative behavior of the constructed dependences, one can trace the dynamics of the formation and evolution of zones characteristic of the process of in-situ combustion and draw a conclusion about the implementation of in-situ combustion in the Karazhanbas field.

Study of the Influence of Dynamic and Static Capillary Forces on Production in Low-Permeability Reservoirs

Low-permeability reservoirs have strong heterogeneity, and the production prediction based on traditional seepage model is not accurate enough. The dynamic capillary-force seepage model can characterize the dynamic heterogeneity of seepage and more accurately describe the oil–water flow process. In this paper, the calculation formula of the dynamic capillary force is obtained through a real low-permeability core experiment, and the seepage model of dynamic capillary force is established. Based on the model, the authors quantitatively study the effects of formation pressure, heterogeneity and production speed on dynamic capillary force through numerical solutions. It is found that compared with the traditional static capillary-force seepage model, the dynamic capillary-force seepage model makes the predicted water cut increase and the recovery factor decrease. With the increase in development time, formation pressure and production rate will make the effect of dynamic capillary force more obvious. According to the comparison of heterogeneous reservoir models, results show that the horizontal heterogeneity will strengthen the dynamic capillary-force effect, while the vertical heterogeneity will weaken the dynamic capillary-force effect. In the range of research parameters, the recovery ratio predicted by the dynamic capillary-force seepage model can be reduced by 4.7%. A new oil–water seepage model is proposed, which can characterize the spatial difference and dynamic change of low-permeability reservoirs with time. It is of great significance for describing the remaining oil distribution of low-permeability reservoirs in detail and making decisions on efficient EOR measures.

Wax deposition modeling in oil-water stratified pipe flow

Wax deposition in oil-water stratified flow is commonly encountered onshore and offshore oil production pipe systems, and typically reduces transportation capacity of oil. The accurate predicted model of wax deposition has becomes an indispensable approach to design effective remediation strategies. However, a reliable mechanistic model for wax deposition prediction in oil-water two-phase stratified pipe flow is lacking to validate the deposition process. In this work, a three-dimensional (axial, radial, and angular) robust wax deposit model for oil-water stratified circular pipe flow was developed. The model of formation of a gel deposit based on the first principles of rheology was developed, associated with the results obtained from hydrodynamics and heat/mass transfer simulations. The predictions for wax deposition are found to compare satisfactorily with experimental data with two different oils for single phase and four different water cuts for oil-water stratified pipe flow. It can be seen from the wax gelation mechanism that an increase in water cut can help to reduce the wall/oil-deposit interface shear stress, thereby leading to an increase in the degree of gelation as well as the deposit rate. Furthermore, a local deposit analysis in the circumferential direction was conducted, for water cut 75% and total flow rate 5 m 3 /h, which provided insights to understand that the thickness on pipe wall was roughly uniformly distributed locates near the top of the pipe and the nearer the position gets close to two points, where the oil-water interface contacts the inner wall, the deposition thickness quickly dropped to 0. It was attributed to the fact that a roughly uniformly thickness far away from the oil-water interface contact the inner wall resulted in the slowly changes temperature along the circumferential pipe wall wetted by oil.