Oil Production Wells Research Articles

Research on the Compounding Scheme of High-Efficiency and Environmentally Friendly Water-Based Well Cleaning Fluid and Analysis of Its Application Effect

In the process of oil well production, the deposition and enrichment of heavy oil and wax are common phenomena. The deposition of these high-viscosity organic substances will not only seriously affect the normal production of oil wells but also cause certain pollution to the environment. Traditional well-washing operations usually rely on high temperatures and strong cleaning chemicals, which have the problems of low cleaning efficiency at low temperatures and poor environmental protection. Therefore, it is particularly important to study a more efficient and environmentally friendly water-based well-washing fluid. At present, most oilfields in China use diesel or organic cleaning agents to clean oil wells, which not only increases the cost of well-washing operations but also may cause pollution to the environment. In response to this problem, the core of this study lies in its innovative compounding scheme. The scheme includes preferred alkaline components, surfactants, emulsifiers, and solubilizers, and introduces glass fiber cutting and erosion technology. This well-washing fluid can effectively remove wax and heavy oil attached to the well wall at a lower temperature, which not only improves cleaning ability but also greatly reduces the dependence on high temperature. The water-based well-washing fluid provided in this study is composed of water, alkaline substances, surfactants, emulsifiers, and glass fibers. Emulsifiers such as Tween 80, OP-20, and polyethers form a stable emulsification system to help disperse and encapsulate oil and grease particles.

Method for determining reagent optimum volume for acid treatments of carbonate reservoirs based on a pressure build-up curve method

Relevance. The need to increase the efficiency of acid treatments of carbonate reservoirs. Often, the design of treatments does not take into account the actual operating conditions of production wells, which leads to an overestimation or underestimation of the required volume of the reagent. Aim. To propose a method for determining the optimal amount of reagent for carrying out acid treatments of carbonate reservoirs in order to restore the permeability of the rock in the near-well zone, taking into account the actual operating conditions of the well, which allows rationalizing the use of subsoil user resources. Objects. Producing oil wells exploiting oil deposits in carbonate deposits of the Perm region, as well as the results of hydrodynamic studies carried out on these wells. Methods. Theoretical substantiation of the possibility of determining the zone of deteriorated permeability around the well using the pressure recovery curve graph, graphical processing of diagnostic graphs of the pressure recovery curve, mathematical calculation of technological indicators based on hydrodynamic testing data of wells, integration of inflow volumes, analysis of technological data and conditions of applicability of the methodology. Results. The authors have developed the methodology for determining the optimal volume of reagent for acid treatments of carbonate reservoirs based on the pressure recovery curve method. The optimal volume of reagent for 21 production wells was calculated. Using the example of 13 wells, the efficiency of the injected volume of reagent was determined and an overestimated volume of reagent injected into the formation was demonstrated. The authors assessed the subsoil user's costs taking into account the excess consumption of the reagent. The factors influencing the success of the method application depending on the operating conditions of the wells were identified. Criteria inappropriateness of acid treatment were identified.

Prophet modeling for oil production forecasting in an enhanced oil recovery field

Accurate daily oil production forecasting is essential for efficient reservoir management and investment strategy. Forecasting oil production in enhanced oil recovery (EOR) and conformance-dominated fields is a complex process due to the nonlinear, voluminous, and often uncertain nature of reservoir parameters and hidden factors. As a result, conventional tools such as decline curve analysis frequently fail to accurately predict daily oil production in conformance-controlled areas. In contrast, machine learning works efficiently for large datasets, even if the parameter values are unknown. The current study employs a Prophet time series forecasting method for five oil production wells in an EOR applied field, but it fails to achieve the desired sweep efficiency. This study compares the results of conventional decline curve analysis (DCA) and popular autoregressive integrated moving average time series forecasting methods with the Prophet model. This is the first attempt to use Prophet for oil well production forecasting, where polymer flooding is used. In all, 60% of the data are used for training, and the remaining 40% are used for testing. The Prophet shows the best performance for all the wells. This study is also the first to handle shut-in data using the Prophet model for oil production. Well-2 achieves the highest accuracy after incorporating shut-in results, with an R2 score of 92%. The result shows that though the DCA performs reasonably well with higher linearity and trend stationary data, Prophet modeling shows superior results than conventional DCA for all EOR applied producing wells.

The development of high-performance kinetic hydrate inhibitors by introducing N-vinyl caprolactam and vinyl ether homopolymers into PVCap

Low dosage kinetic hydrate inhibitors (KHIs) are a kind of alternative chemical additives to prevent gas hydrate formation in oil & gas production wells and transportation pipelines. In this work, a series of KHIs were experimentally synthesized with N-vinyl caprolactam (N-VCap) and vinyl ether including vinyl ether, vinyl n-butyl ether, vinyl isobutyl ether, triethylene glycol divinyl ether, with the mole ratio ranging from 9:1 to 5:5. The inhibition performance of new-synthesized KHIs on the formation process of methane hydrate were examined and compared with that of commercial N-vinyl caprolactam PVCap. Several ethylenediamine reagents were used as synergists and tested to improve the inhibition capacity of new-synthesized KHIs. The experimental results demonstrate that the introduction of ether groups on PVCap improves the performance of hydrate inhibitors. PVCap-VNBE (N-VCap: vinyl n-butyl ether = 5:5) showed the best inhibition performance for methane hydrate, which could extend the TVO to 1251 min under 6 K subcooling. N,N'-dimethylethylenediamine shows the best synergistic effect for PVCap-VNBE (5:5), and extends the TVO by 2.75 times at 7 K subcooling. Additionally, the relationship between hydrate inhibition performance and interfacial tension of newly-synthesized KHIs under high pressure were studied. It shows that the lower interfacial tension of KHIs would result in longer onset time, exhibiting better inhibition performance.

Elevated airborne radioactivity downwind of a colorado oil refinery

ABSTRACT Airborne radioactivity from fossil fuel production systems is poorly characterized, but a recent study showed elevated ambient levels with proximity to oil and gas production wells. Here, we report year-long, high temporal resolution monitoring results of airborne alpha radioactivity from both radon gas and radon progeny attached to particulates immediately northeast of an oil refinery in Commerce City, Colorado, USA, in an environmental justice community of concern. Gas and particle-associated radioactivity contributed nearly evenly to the total alpha radioactivity. Total radioactivity levels of 30–40 Bq m−3 were 2–3 times higher than background levels (~10–15 Bq m−3) when winds were light and southwesterly, suggesting the refinery as the geographic origin. Furthermore, elevated airborne radioactivity tracked most closely with the light hydrocarbon and natural gas tracer ethane. Thus, the data imply natural gas as the radon emission carrier, possibly from flaring. However, this could not explain all our particle-associated radioactivity observations. Our findings are unique and suggest a need for further investigations of radon emissions from oil and gas infrastructure such as natural gas processing plants, compressor stations, petrochemical plants, and oil refineries that process oil and natural gas from unconventional production. Implications Statement: Regulatory agencies currently do not mandate or conduct monitoring of radioactivity releases and public exposure from petroleum industry air emissions. This study reports elevated radioactivity from radon gas and nonvolatile radon decay products attached to particulate matter, at about 2-3 times above background levels in proximity to Colorado’s largest oil refinery. Observations were within an environmental justice community of concern that experiences well above-average exposure to many other harmful atmospheric pollutants, suggesting potential adverse health effects from this cumulative exposure. Our findings offer actionable insights for policymakers, industry stakeholders, and affected communities alike.

Using in situ measurements of δ13C in methane to investigate methane emissions from the western Canada sedimentary basin

During COP26, Canada joined the Global Methane Pledge aiming to reduce global methane (CH4) emissions by 30% below 2020 levels by 2030. Rapid reduction of anthropogenic CH4 emissions in the atmosphere is considered one of the most effective strategies to slow global warming in concert with carbon dioxide mitigation measures. In Canada, a large part of anthropogenic CH4 emissions can be attributed to the oil and gas industry in the Western Canada Sedimentary Basin (WCSB), which is the fourth largest reserve of fossil fuel in the world. Recent studies highlighted big discrepancies between CH4 emissions reported in Canada's National Inventory and emissions estimated with approaches using atmospheric measurements for the oil and gas sector. Measuring the isotopic signature of CH4 (δ13CH4) at different atmospheric monitoring stations and comparing these measurements to detailed archives of δ13CH4 from oil and gas wells and associated CH4 leaks in the WCSB could help better characterize the emissions from different CH4 sources over the region. In this study, we compare two independent sets of data: (1) thousands of δ13CH4 of samples from oil and gas production wells and their associated leaks (surface casing vents and ground migration) collected across the WCSB, and (2) atmospheric mixing ratios of CH4 and their δ13CH4 measured successively at three locations across this region between 2016 and 2020 combined with their atmospheric footprints modeled with HYSPLIT-STILT. We observed a gradient in the isotopic signatures of the oil and gas samples within the WCSB with δ13CH4 being more depleted in the Southeast than in the Northwest. The analysis of these samples showed that the isotopic signature of CH4 emitted by the production of fossil fuel depends on the geological formations from which it is extracted. Also, CH4 isotopic signatures vary more depending on the region where CH4 comes from than on the type of fossil fuel extracted (natural gas, oil, heavy oil, shale gas). The atmospheric measurements showed a strong seasonality of δ13CH4 at one of the atmospheric monitoring sites with isotopic signatures associated with thermogenic sources in winter and isotopic signatures associated with a mix of biogenic and thermogenic sources in summer. Using the δ13CH4 archive database from oil and gas samples, we estimated that 28–39 % of the CH4 emitted near this site in summer was coming from a biogenic source (most likely wetlands). Ultimately, atmospheric measurements collected during winter combined with their associated HYSPLIT-STILT footprints presented a spatial distribution of δ13CH4 over the WCSB comparable to the one observed in the archive database from the oil and gas sector, confirming that the oil and gas sector is the main source of CH4 in this region.

Dual-Parameter Prediction of Downhole Supercritical CO2 with Associated Gas Using Levenberg–Marquardt (LM) Neural Network

This research investigates the application of supercritical carbon dioxide (CO2) within carbon capture, utilization, and storage (CCUS) technologies to enhance oil-well production efficiency and facilitate carbon storage, thereby promoting a low-carbon circular economy. We simulate the flow of supercritical CO2 mixed with associated gas (flow rates 3–13 × 104 Nm3/d) in a miniature venturi tube under high temperature and high-pressure conditions (30–50 MPa, 120–150 °C). Accurate fluid property calculations, essential for simulation fidelity, were performed using the R. Span and W. Wagner and GERG-2008 equations. A dual-parameter prediction model was developed based on the simulation data. However, actual measurements only provide fluid types and measurement data, such as pressure, temperature, and venturi differential pressure, to determine the liquid mass fraction (LMF) and total mass flow rate (m), presenting challenges due to complex nonlinear relationships. Traditional formula-fitting methods proved inadequate for these conditions. Consequently, we employed a Levenberg–Marquardt (LM) based neural network algorithm to address this issue. The LM optimizer excels in handling complex nonlinear problems with faster convergence, making it suitable for our small dataset. Through this approach, we formulated dual-parameter model equations to elucidate fluid flow factors, analyzing the impact of multiple parameters on the LMF and the discharge coefficient (C). The resulting model predicted dual parameters with a relative error for LMF of ±1% (Pc = 95.5%) and for m of ±1% (Pc = 95.5%), demonstrating high accuracy. This study highlights the potential of neural networks to predict the behavior of complex fluids with high supercritical CO2 content, offering a novel solution where traditional methods fail.

A Study on Effect Analysis and Process Parameter Optimization of Viscous Acid Acidification in a Porous Heterogeneous Carbonate Reservoir

The homogeneous acid etching of conventional acid in porous heterogeneous carbonate reservoirs leads to a large amount of consumption in the near-wellbore area, which makes the acidification effect often not ideal. In order to improve the acidizing effect of porous heterogeneous carbonate reservoirs, viscous acid is used to increase the stimulation of the target block in this paper. Through systematic experiments, the adaptability of the viscous acid in the four layers of the M reservoir in the target block was evaluated, and the MD and ME layers suitable for acidizing stimulation were determined in combination with physical property analysis. Finally, based on the geological characteristics and experimental data of the preferred layers, a two-scale acid wormhole growth radial model was established, and the construction parameters of acidizing stimulation were optimized. The results show that (1) The preferred viscous acid system has a dissolution rate of more than 95% for the rock powder in the four layers. When the matrix permeability is high, the effect of the acid wormhole is obvious and the permeability increase is higher. (2) The steel sheet corrosion and residual acid damage experiments showed that the acid system was not corrosive to the wellbore, and the reservoir damage rate of the residual acid after the reaction was low. (3) Based on the relationship between reservoir porosity and permeability and the position of edge and bottom water, the MD and ME layers with more potential for acidizing stimulation are selected. (4) The results of the numerical simulation show that the optimal acid pump rate of the MD and ME layers is 1.4 bpm and 1.0 bpm, and the acidizing fluid volume is 255 bbl, which can form effective acid wormholes, and the range of reservoir permeability transformation is the largest. The field application results show that the optimization scheme effectively improves the production of oil wells, verifies the practicability of the scheme, and provides a reference for the process optimization of viscous acid in the same type of porous heterogeneous carbonate reservoir stimulation.

SCALE INHIBITOR SQUEEZE TREATMENT: AN ADVANCED BIBLIOMETRIC ANALYSIS

The scale inhibitor squeeze treatment is an important method used in the petroleum industry to control formation of inorganic deposition within the oil production wells. This treatment increases the life cycle of petroleum production by preventing or reducing the formation and growth of salt crystals. In recent years, studies on inhibitor squeeze treatments have been expanding and diversifying with the goal of improving the lifespan and reducing treatment costs. This study reports an advanced bibliometric analysis from 1970 to 2023, illustrating the extent of research on inhibitor squeeze treatments to prevent the formation of inorganic scale, with a systematic survey since the first registered publication. It highlights the evolution of research reports, assessing the relationships between institutions, journals, and authors, identifying of potential needs to be addressed by future investigations.

Prediction of emergency-free operation of production wells with a horizontal termination under conditions of high removal of mechanical impurities on the example of the Severo-Komsomolskoe field

Relevance. As readily available oil reserves are developed and production technologies develop, oil and gas companies are gradually moving to the development of previously unprofitable assets. Over the past five years, several oil-and-gas condensate fields with oil rims have been put into operation in Western Siberia. Their development is further complicated by oil high viscosity and poor cementation of the reservoir rocks. Low values of critical drawdown do not allow oil to be produced without destruction of the productive formation, and mechanical impurities entering the well lead to spillage of perforation intervals and downhole equipment failures. The use of mathematical modeling in relation to the operation of wells in the conditions of the removal of mechanical impurities will make it possible to control production and select the optimal well operation mode. Aim. Forecasting the trouble-free operation of a production well under conditions of high removal of mechanical impurities. Objects. Producing oil wells; the subject of the study is the movement of solid particles in the wellbore of a production well, the relationship and dependence of formation of sand plugs on the operating parameters of the well. Methods. Theoretical research methods – analysis (analysis of models for calculating the critical flow velocity in a horizontal pipe (calculation of the critical velocity in a single-phase flow; calculation of the critical velocity in a multi-phase flow; calculation of the critical velocity based on the balance of forces)) and modeling (simulation of work wells with the removal of mechanical impurities). The totality and combination of these methods are adequate to the goals and objectives, the object and subject of the study of this work. Results. The problem of sand production is typical not only for fields that are in the late stages of development, but also for fields that have recently been put into operation. Sand shows up are a complicating factor in the operation of wells at the Severo-Komsomolskoe high-viscosity oil field located in Western Siberia. The main object of development of the studied field is a weakly cemented sandy layer. Oil production in such difficult areas requires a very careful approach to the choice of development system, to the selection of methods to deal with complications, including the choice of the right method to limit sanding. However, regardless of the approach taken to solve the problem of sand production, some rock will still flow into the well. To prevent the formation of sand plugs, it is necessary to understand the nature of the movement of solid particles along the wellbore. It is possible to assess whether a well is capable of carrying out solid particles from a horizontal section using modeling in specialized software products. Modeling of the well operation, taking into account the influence of mechanical impurities, made it possible to solve the following problems: 1) determine the fluid to carry rock particles out of the horizontal section; 2) identify the areas in which there is a risk of sand plugs; 3) present the dependence for calculating the critical speed for high-viscosity oil with different water cut; 4) assess how the water cut and gas factor affect well operation in conditions of high removal of mechanical impurities; 5) calculate the time of formation of sand plugs.

PREVENTION OF CRYSTALLISATION OF ASPHALT-RESIN-PARAFFIN DEPOSITS UNDER THE INFLUENCE OF A PERMANENT MAGNETIC FIELD

During the operation of oil production wells, significant losses occur due to asphalt-resin-paraffin deposits (ARPD) in the pores of reservoirs and lift pipes. Understanding the detection and technology for combating ARPD is an urgent scientific, technical, and practical task, as this factor affects the wells’ operability and ultimate productivity. Keywords: oil products pipeline transportation, high-viscosity oil, paraffin deposition, permanent magnetic field.

Fault system dynamics and their impact on ordovician carbonate karst reservoirs: Outcrop analogs and 3D seismic analysis in the Tabei region, Tarim Basin, NW China

The Tabei Uplift in the Tarim Basin of NW China represents an area with significant hydrocarbon exploration potential. This paper describes the effects of multi-phase faults on structural and hydrocarbon systems in the Tabei Uplift utilizing high-quality 3-D seismic, geological outcrops and drilling and production data. The interpretation and analysis of 10 fault systems from the Cambrian through the Cretaceous, shows that the deep, middle and shallow faults developed in four stages: the Early Caledonian, Mid-Late Caledonian, Hercynian and Himalayan. Specifically, the Early Caledonian fault system is favorable for the hydrocarbon expulsion of Cambrian source rocks, while Mid-Late Caledonian strike-slip faults facilitate hydrocarbon migration and accumulation. Hercynian and Himalayan strike-slip faults were formed as a result of the reactivation of the Mid-Late Caledonian strike-slip faults and have a destructive effect on the older oil reservoirs. Similarly, Permian volcanic activity also caused varying degrees of damage to Ordovician reservoirs. Oil production along fault zones more than 100 km show that the complex fracture-vuggy (FV) structure is more likely to trap oil and gas when it is damaged than the simple FV structure. Fault-controlled, fracture-vuggy carbonate reservoirs (FVCRs) were classified into six grades, which correlate to the productivity of oil wells in the region. Using this classification system, several drilling locations were selected and resulted in 80% success rate. This classification provides a novel approach for assessing the interplay between fault activity and reservoir formation, enhancing the prediction of hydrocarbon potential in varying strike-slip fault zones. This analysis not only refines our understanding of the region's geodynamic history but also aids in optimizing exploration and development strategies.

Development and simulation of the gas-downhole water sink-assisted gravity drainage (GDWS-AGD) process to reduce carbon footprint and improve clean oil production by injecting CO2 and petroleum-associated gas

Implementing continuous gas injection into oil reservoirs, surrounded by strong water drives, enhances oil production. Nevertheless, water coning/cresting in these reservoirs leads to high water cuts, substantial oil production reductions, and major water-handling issues for surface facilities. The Gas-Downhole Water-Sink-Assisted Gravity Drainage (GDWS-AGD) process can enhance oil recovery (EOR) in such reservoirs and mitigate the influx of aquifer water into the oil zone. This study compares the performance of GDWS-AGD and GAGD processes based on reservoir-simulation results for two heterogeneous reservoirs: the PUNQ-S3 reservoir and the giant South Rumaila (SR) oil field (Iraq).The PUNQ-S3 simulation exclusively employs carbon dioxide (CO2) as the injected gas. In contrast, the SR simulation evaluates the CO2 injection in comparison to petroleum-associated gas (PAG). The GDWS-AGD process performance was assessed based on oil recovery factor, water cut, gas-to-oil ratio (GOR) in oil producers, cumulative volumes of gas injected, and oil/gas saturations. The PUNQ-S3 simulation employs six wells: two vertical CO2 injectors with perforations at the top of the reservoir to form a gas-cap zone. Additionally, there are two horizontal oil-production wells and two horizontal water-production wells positioned below the oil-water contact (OWC). The GDWS-AGD process was assessed in the SR simulation, using CO2 and PAG, in several configurations to compare it with the basic GAGD. In the SR design, twenty-two vertical gas-injection wells, ten horizontal oil-production wells, and six horizontal water-production wells were placed in the gas-, oil-, and water-bearing zones, respectively. A vertical well was dual-completed with two lateral sections originating from separate kick-off points above and underneath the OWC with 2–3/8-inch tubing for oil and water production, respectively. Hydraulic packers in the vertical wellbore separate oil and water production tubing in the dual-completion configuration, and electric-submersible pumps are then employed for water production.The downhole-water-sink configuration effectively reduces oil-reservoir pressure and minimizes water cut/cresting tendencies. CO2 remains immiscible due to reduced gas-injection pressure and decreased solubility. The CO2-based simulation of the SR field yielded oil-recovery factors of 71.67%, 75.25%, and 76.162% for the GAGD, basic, and advanced GDWS-AGD setups, respectively. The oil-recovery factor of GDWS-AGD was further increased to 82.64% by implementing PAG injection, resulting in a decrease in water cut to 5% in all oil producers. Although PAG gas injection outperforms CO2 in oil recovery, water cut, and gas injectivity in the SR field simulation, the GDWS-AGD approach with CO2 remains a feasible option. This technology has the capability to effectively capture and store significant amounts of CO2 in the flooded reservoir for many years, thereby mitigating carbon emissions associated with fossil fuel usage.

Design and performance study of gas–liquid separation–mixing device for electric submersible pump in high-gas-content oil wells

In the process of oil production, wells containing gas can impact the efficiency of electric submersible pump (ESP), potentially causing gas lock. This issue can lead to the loss of lifting capacity in ESP, affecting the normal production of oil wells. To address this problem, the concept of gas separation before mixing transportation has been proposed, and a gas–liquid separation–mixing device has been designed. Experimental tests on the gas–liquid two-phase flow under various working conditions were conducted. A numerical model of the physical process was developed and validated with the experimental results. The results indicate that when the inlet flow rate exceeds 8.75 m3/h, the gas phase can be effectively accumulated in the center of the main pipeline after flowing through the guide vanes, thereby achieving efficient gas–liquid separation. Centrifugal number, which is defined as the ratio of axial flux of centrifugal force to axial flux of gravity, was proposed for evaluating the flow characteristics. When the centrifugal number exceeds 6.5, a high-quality gas core is formed in the pipe. At high inlet gas content, the volume fraction of gas in the main pipe initially decreases to 2% as the flow rate increases to 15 m3/h. However, at a flow rate of 30 m3/h, the volume fraction gradually rises to 30%, which results in a significant amount of gas being forced into the main pipe. The results are beneficial for expanding the use of ESP and improving the lifting efficiency in the development of oil field with high gas content.

Enhancing CO2 Injection Efficiency: Rock-Breaking Characteristics of Particle Jet Impact in Bottom Hole

Storing CO2 in oil and gas reservoirs offers a dual benefit: it reduces atmospheric CO2 concentration while simultaneously enhancing oil displacement efficiency and increasing crude oil production. This is achieved by injecting CO2 into producing oil and gas wells. Employing particle jet technology at the bottom of CO2 injection wells significantly expands the bottom hole diameter, thereby improving CO2 injection efficiency and storage safety. To further investigate the rock-breaking characteristics and efficiency, a finite element model for particle jet rock breaking is established by utilizing the smoothed particle hydrodynamics (SPH) method. Specifically, this new model considers the high temperature and confining pressure conditions present at the bottom hole. The dynamic response and fracturing effects of rock subjected to a particle jet are also revealed. The results indicate that particle jet impact rebound significantly influences the size of the impact crater, with the maximum first principal stress primarily concentrated on the crater’s surface. The impact creates a “v”-shaped crater on the rock surface, with both depth and volume increasing proportionally to jet inlet velocity and particle diameter. However, beyond a key particle concentration of 3%, the increase in depth and volume becomes less pronounced. Confining pressure is found to hinder particle impact rock-breaking efficiency, while high temperatures contribute to larger impact depths and breaking volumes. This research can provide theoretical support and parameter guidance for the practical application of particle impact technology in enhancing CO2 injection efficiency at the bottom hole.

A critical review on analysis of sand producing and sand-control technologies for oil well in oilfields

Sand production in oil wells seriously affects the production of oil and gas in oilfields. Although conventional sand-control techniques can effectively prevent sand production, it may also limit the productivity of oil wells. Fracturing and packing sand control technology changes the distribution of pressure and flow in the wellbore, while foam polymer resin diversion technology reduces the anisotropy of reservoir permeability and increases the area of oil leakage in the reservoir, both achieving the goal of sand control and increased production. The sand-free production rate is successfully increased thanks to zeta potential sand control technology, which modifies the formation’s sand potential and causes the sand to agglomerate without harming the reservoir. This article first looks into the causes of sand production in oil and gas wells before examining the fundamentals, implementation strategies, and effects of traditional sand control techniques, fracturing and filling sand control technology, foam polymer resin diversion technology, and Zeta potential sand control technology. In this article, the experience of sand control technology in actual oil field applications is summarized, explained in detail, and the future development possibilities of sand control technology are discussed.

DEVELOPMENT OF DOWNHOLE PUMP VALVE ASSEMBLY

The purpose of the work is modernization of the valve, in order to increase reliability, wear resistance, increase the pump flow and reduce the load on the rod string, as well as improve durability. The sucker rod pump is one of the most popular and extensively utilized artificial lift systems. It is a frequently chosen option for lifting oil because of its fundamental simplicity, low operating costs, and adaptability in power supply. In the long run of oil production history, sucker-rod pumping was the first option—and frequently the only option—when artificial lift was required. For this reason, the oldest and most popular method of producing oil wells worldwide is sucker-rod pumping. Since the steel used to make rods has limited strength, sucker-rod pumping is typically thought of as a way to raise moderate to low liquid production rates from shallow to medium well depths due to depth restrictions. Since the correct working of the standing and traveling valves is largely responsible for an efficient pumping operation, valves are regarded as the heart of the sucker-rod pump. The extremely high differential pressures across the valve during pumping necessitate a highly dependable sealing action between the ball and the seat. Small initial flaws in the sealing surfaces or subsequent corrosion- or abrasion-related problems result in greater liquid slipping and a quick decline in valve function because of fluid cutting. Subsurface pumps using traditional ball-and-seat valves suffer a number of basic operational issues: • Because of the greatly high number of pumping cycles per day, the sealing surfaces may sustain significant damage from the frequent collision of the two parts against one another. • In deviated wells, valve wear is uneven and can cause premature failure. • Typical cage constructions, meant to limit impact damage, typically restrict the flow area available through the valve and can be the source of pumping inefficiencies due to low fillage of the pump barrel. Keywords: sucker rod pumps, downhole pump, traveling valve, standing valve, valve assembly.

Power consumption of electric centrifugal pumping plants under extraction of highly watered oil

Relevance. Currently, oil fields in Russia are mainly developed using the method of artificial maintenance of reservoir pressure to achieve high oil recovery. The use of artificial impact on productive formations by the method of water injection contributes to the premature irrigation of production wells. Water content of productive layers in oil fields significantly complicates the technology of oil production. With the increase in water content of the surface fluid, the power consumed by the engine increases. Minimization of energy consumption is quite relevant, as oil is produced with significant expenditures of electrical energy. It is important to investigate the dependences of the electric energy consumption on the well water cut. Aim. To study the dependence of energy consumption of submersible electric centrifugal units operated in oil production wells on water cut. Methods. Submersible electric centrifugal installations for oil production. Results. In order to study the effects of formation water cut on electrical energy specific consumption, wells with a water cut of more than 90% were selected. Using the formula, the authors have calculated the electrical energy specific consumption for oil production. The analysis of the results of the calculated data showed that in producing wells with a water cut of up to 90 %, the average specific electric power consumption for oil production is within the recommended standards. In wells with the water cut more than 90%, the average specific electric power consumption for oil production exceeds recommended specific norms of electric energy consumption during operation of oil producing wells equipped with electric centrifugal installations. Based on calculated data, the dependence of the specific electrical energy consumption for oil production on the water cut of reservoir products was plotted, and wells with a water cut of more than 90% were selected. The analysis of the graphical dependence showed that in wells with an oil water cut of more than 90%, the specific energy consumption reaches maximum values ​​(the specific energy consumption increases by 40%).

Experience in modeling an asphaltene depositions curve and reducing the intensity of their formation by optimizing oil production technology

Relevance. The need to study the formation of asphaltene deposits in oil production wells. Among the known methods of combating these complications, the greatest interest is in optimizing oil production technology to prevent or reduce the intensity of the formation of these deposits. Aim. To study the possibility of constructing a curve for the formation of asphaltene deposits on the laboratory installation “Wax Flow Loop” and to determine the possibility of optimizing oil production technology to prevent the formation of these deposits. Methods. Laboratory studies on the “Wax Flow Loop“ installation, modeling based on the component composition of oil in the “PVTSim“ software product, calculations in the “Engineering Simulator of Technological Processes“ software product. Results. Based on the results of laboratory studies and numerical calculations, it was possible to construct a curve for the formation of asphaltene deposits. The correctness of the curve was validated against actual data on plugging a production well. The calculation of the influence of installing an electric centrifugal pump and choke-fitting a well showed that the first technology for changing oil production can significantly reduce the intensity of the formation of asphaltene deposits by introducing additional energy. The second technology only slightly shifts the thermobaric conditions of liquid extraction, which does not significantly affect the intensity of the formation of asphaltene deposits. Conclusions. The laboratory installation "Wax Flow Loop" allows correctly forming the curve of asphaltene deposits formation in the production tubing of oil producing wells. Methods for optimizing oil production technology make it possible to prevent the formation of asphaltene deposits with correct modeling and numerical calculations and selection of downhole pumping equipment.

Restoration of Rock Permeability Degraded by Well Killing Fluid Using Ultrasonic Vibrations: Experimental Studies

The operation of oil production wells is accompanied by the invasion of well killing fluids into a near wellbore zone while well intervention which deteriorates rock permeability and decreases well oil rate. In order to restore the permeability of the rock in the near wellbore zone of the formation, it is proposed in this work to use ultrasonic alternating loading during well inflow stimulation. To study the effect of alternating loading on the permeability of rocks, a laboratory set-up is developed and filtration experiments are carried out. The rock studied was sandstone of medium permeability. The experimental studies included four stages: filtration of the killing fluid (calcium chloride solution) in the forward direction (simulating well killing); keeping the sample in conditions of pumped kill fluid; filtration of kerosene in the opposite direction (simulating an inflow stimulation) until the maximum possible restoration of permeability; filtration of kerosene in the reverse direction under ultrasonic alternating loading conditions for additional permeability restoration. It was revealed, that under conditions of ultrasonic alternating loading, the pore space of the rock, previously blocked by particles of the killing fluid, is unblocked and the permeability of the samples is restored. An analysis was made of the mechanism of blocking the pore space with the killing fluid and restoring the permeability of the rock.