Downhole Pumping Research Articles

Methodology for Analyzing the Actual Technical Condition of Downhole Pumping Equipment

The reducing in the pressure characteristic of the submersible pump during operation occurs as a result of the combined action of a number of reasons. Pumping equipment wears out due to waterjet destruction of flow channels. The characteristics of submersible pumps are captured at the factory on special stands. At large group groundwater intakes, wells are equipped with an automated control system that allows testing the pump at the workplace and promptly making a decision on its replacement if the pressure characteristic is unacceptably reduced. The actual pressure characteristic of the pump H н = f (Q) can be plotted directly in the well with a sufficient degree of accuracy. To determine the degree of wear of the pump, its pressure characteristics are compared before installation and at the time of taking readings. The article describes a well strapping scheme for measuring the specific flow rate and pressure characteristics of a submersible pump. The purpose of the study is to derive a dependency for constructing the flow-pressure characteristics of a submersible pump at its workplace and to develop a method for accounting for its wear during operation, which allows predicting a decrease in well productivity over time. An expression is proposed to describe the characteristics of the pump at any time, calculated from its installation in the well. The analysis of the reducing in the pressure characteristics of pumps produced by various manufacturers in the wells of the existing water intake of underground water is presented. It is confirmed that the intensity of the pressure reduction depends on the duration of the pump operation in a given well, the material of the pump impellers and the sand content in the pumped water.

Определение минимальных мероприятий в скважине по предотвращению образования асфальтосмолопарафиновых отложений

An analysis of the formation of asphaltene resin paraffin deposits is presented, criteria for assigning wells to subgroups of the complications type are considered, and a classification of complications in oil production is proposed. Oil is a complex and varied mixture of various hydrocarbons, both light and heavy, in thermodynamic equilibrium under reservoir conditions. In some fields, oil production is not accompanied by the formation of asphaltene resin paraffin deposits on the downhole pumping equipment, while in others it is complicated by them. Methods of preventing the deposition of asphaltene resin paraffin deposits and methods of dealing with them are considered, the research work done to substantiate the use of chemical reagents to prevent the formation of complications in oilproducing wells is presented, the minimum measures for subgroups of the proposed classification, complicated by asphaltene resin paraffin deposits of the fund, are presented. The methods for determining the effectiveness of the asphaltene resin paraffin deposits inhibitors, developed in the PermNIPIneft branch of LLC LUKOIL-Engineering, were briefly presented, on the basis of which the studies were carried out. The results of studies on the selection of reagents and determination of their effectiveness for the production well stock complicated by asphaltene resin paraffin deposits were considered. It was found that during wells operation where the physicochemical properties changed, the effectiveness of the inhibitor significantly decreased and did not reach the efficiency criterion of 75%. So, in oil production it is necessary to periodically, at least once every three years, check the effectiveness of the selected reagents, as well as analyze changes in such parameters of the processed object as: change in the physicochemical properties of the fluid; geological and technical measures at the well; significant increase, decrease in production; involvement or isolation of interlayers, production facilities; changes in reservoir, bottomhole pressure during operation. Approaches for wells are proposed: where, as a result of research, the criterion of the effectiveness of chemical reagents has not been achieved, it is necessary to select other methods to avoid the complication.

OIL MOVEMENT FEATURES IN THE ANNULUS OF THE WELL

Background The article considers the state of the gas-liquid mixture in the annulus of the well, adjusts the model of oil movement from the well pump to the dynamic liquid level. A positive example of demulsificator injection from the well-head into the annulus of difficult wells at the oil field in the Republic of Bashkortostan is given. Aims and Objectives To evaluate the state of fluids in the annulus of oil producing wells in order to develop a movement model of reactants to the suction of well pump without squeezing it with well fluid or overflush fluid. To evaluate the results of the field experiment on demulsificator injection in the annulus of oil wells producing high-viscosity oil-in-water emulsion. To develop a technical solution in order to reduce associated petroleum gas separation from oil of the annulus to gas environment of the well and normalize the operation of the downhole pumping equipment. Methods The comparative analysis of the existing model of gas-liquid mixture in the annulus of the wells using its density according to the data from thermo-manometric systems is performed. The effectiveness of the demulsificator under laboratory conditions and in the course of the experimental application at the wells by its dosing into the annulus of the wells is considered. Results The most of two-way movement of the oil in the annulus of oil producing wells is adjusted. The most effective demulsification reactant for the considered wells is determined, and its application on 3 wells of the Meneuzovskoye oil field is evaluated. The necessity of oil turbulization in the annulus of the wells is proved, the fastening scheme of devices with a spiral ribbed surface in the flow column is developed.

AN APPROACH TO ESTIMATING THE RATE OF ORGANIC DEPOSIT FORMATION IN A HOLLOW ROD STRING AND SELECTION OF METHODS FOR DEPOSIT PREVENTION

Background. There is currently a lack of a methodology that can enable highly-precise determinations of rates of asphaltene deposit (AD) formations in case of dual operation of two oil reservoirs via a single multi-zone oil-producing well using small-bore hollow rods as part of downhole pumping equipment. This methodology aims to minimize the costs of oil and gas companies for servicing such oil wells and preventing their failure. Aims. Creating a methodology aimed at accurate quantitative estimations of the organic deposit formation rates at the inner part of the hollow rod strings. Methods. Calculations of temperature distributions along the hollow rod string inner surface; graphic presentations of the calculated data; laboratory tests using a Cold Finger unit for the selected sections of the hollow rod strings and the graphic presentations of the results. Results and Discussion. The suggested algorithm was field-tested at a target multi-zone oil-producing well of Pavlovka oil field in Perm Krai of the Russian Federation. Using the suggested algorithm, a variation in organic deposit formation rates along the hollow rod string length was evaluated, and the depth of the maximum deposit formation rate was determined. To prevent the deposits in question along the hollow rod string at a target oil-producing well of Pavlovka oil field, laboratory tests were conducted to determine the efficiency of employing the chemical technology, i.e., the use of AD inhibitors, as well as a technology for the removal of the formed deposits using AD solvents. Conclusions. The proposed algorithm is more accurate and requires less time and money compared to existing algorithms. It enables the most effective evaluation of the formation depth of the organic deposits and the intensity at these marks. When evaluating the laboratory studies results, it can be noted that the use of the considered technologies to eliminate organic deposits is highly effective and can be used for this purpose.

Analysis of the efficiency of horizontal drilling in the fields of JSC «Embanumaygas»

One of the directions for increasing the recovery factor, effective development of uncovered reserves, as well as maintaining current production, is drilling horizontal wells (hereinafter referred to as HW). The paper considers and provides the analysis for all EMG fields that have current geologic and hydrodynamic models used to select and calculate the design horizontal well locations.
 In the paper the authors defined the necessary conditions for increasing the efficiency of horizontal drilling, optimized the length of the horizontal section, analyzed well areas, examined the sector hydrodynamic models, carried out the factor analysis of actual flow rates and the analysis of the current operation of downhole pumping equipment, analyzed changes in the physical and chemical properties and the energy state of the horizontal well zones.

Development and application of a double action acidic emulsion for improved oil well performance: laboratory tests and field trials

Emulsified acid has attracted considerable attention of the oil and gas industry due to its delayed action that allows deeper penetration of acid into the formation which essentially facilitates improved well productivity, and at the same time minimizes corrosion of the downhole equipment. In this paper, for the first time, we report a new acidic emulsion suitable for acidizing carbonate reservoirs. The novel emulsion is of a double action type so that it is capable of simultaneously dissolving paraffin deposits and acidizing rocks thus increasing reservoir permeability and porosity. Results of the laboratory experiments and field tests indicate that the new emulsion reacts with carbonate rocks at reduced rate thus enabling the emulsion to penetrate deeper into the reservoir when injected for acidizing. At the same time the emulsion has lower corrosive effect towards steel, thus indicating better compatibility with downhole pumping equipment. Coreflooding experiments confirm the ability of the emulsion to acidize rocks forming highly permeable channels to the flow of hydrocarbons thus stimulating carbonate formations. The initial increase in oil recovery obtained after the acidizing operation suggests that the new emulsion provides better and faster return on investment thus making its use more economically viable. In addition, the developed and tested in this study emulsion requires fewer operations during its field implementation thus significantly reducing the operational costs. The developed novel emulsion, therefore, has characteristics comparable or exceeding those of solutions investigated or used thus far, combining all advantages in a single fluid thus allowing a highly efficient stimulation of production wells that can be achieved in a single operation. Hence, the presented results suggest that the double action emulsion presents a major advancement in acidizing science and technology.

Solution of the Problem of Annular Space Gas Utilization in Wells Operated by Walking-Beam Pumping Unit

This article presents new approaches to solving one of the problems encountered in many oil fields - the disposal of gas accumulating in the annular space of production wells operated by walking-beam pumping units. This question is relevant because the accumulation of gas and the increase in its pressure affects the depression reduction and the fall of the dynamic level of the liquid, adversely affecting the downhole pumping equipment operation. Critical annular pressure is a value above 10 atm. Traditionally in order to bring the annular gas pressure in line with the linear, reverse wellhead valves installed in the wellhead fittings were used. The use of these valves reduces the annular gas pressure, but does not solve the problem of its subsequent disposal. The emphasis is on the technical and economic efficiency of the proposed associated gas utilization method.

Дослідження режиму роботи верстата-гойдалки під час розгону

Розроблена математична модель свердловинної штангової насосної установки з балансирним приводом – верстатом-гойдалкою. Більшість свердловин Українських нафтових родовищ знаходяться на пізній стадії розробки, тобто їх дебіт нижчий ніж подача штангових насосів. Така робота верстатів-гойдалок приводить до зниження динамічного рівня рідини в свердловині, а отже й до зміни навантаження привода. Таким чином порушується усталений режим роботи. Коли рівень рідини досягає прийому глибинного штангового насоса, верстат-гойдалку відключають. На кривошипах верстата-гойдалки встановлено противаги, які зрівноважують навантаження, що діє в точці підвіски штанг. Зміна динамічного рівня призводить до порушення зрівноваження. Таким чином двигун привода перевантажується під час пуску верстата-качалки. Проведено аналітичне дослідження свердловинної штангової насосної установки під час її пуску.

Technology Focus: Artificial Lift (March 2020)

Technology Focus Since I began writing this feature 2 years ago, I have purposely avoided discussing the elephant in the room, but it seems that now the time is right to give the topic its due. Just as the unconventional revolution has transformed our industry during the past decade, it has also dominated the world of artificial lift. In fact, it can be difficult to find an artificial lift paper or presentation these days that does not address, in some way, the design and operation of artificial lift systems in unconventional shale oil wells. Challenges abound for operators attempting to deploy artificial lift systems in unconventional applications. As always, operators set a variety of challenging business and operational goals for themselves: minimize capital and operational expenditures; maximize drawdown over the well’s life; and minimize downtime, failure frequency, and intervention frequency. The unique nature of these wells can make it challenging to achieve many of these goals, let alone all of them. Because the wells are drilled directionally (and often in a hurry), the wellbore may feature small-diameter casing, high dogleg severity, and high tortuosity. The production profile of these wells can vary dramatically over a short period of time—wells initially producing over 10,000 STB/D can produce as little as 50 STB/D just a few years later. Further complicating matters, unconventional wells often produce fluids with high gas/liquid ratios and require pumps to be set above the producing interval, making gas handling a challenge. To make matters worse, the wells typically pro-duce solids early on, and they may suffer from a variety of flow-assurance issues, including asphaltenes, paraffin deposition, hydrates, and severe slugging. All of these can make it extremely challenging—if not impossible—to achieve reliable operation with downhole pumping systems. For this reason, something surprising has happened: Gas lift has emerged as the lift method of choice in new onshore completions in these basins. While gas lift may be the “easy button,” it is not without its share of challenges. In many areas, there is a lack of adequate supply gas or compression equipment. Hydrates are common in the winter months. Limited injection pressure combined with a rapidly varying production profile can lead to frequent, costly interventions. Because the gas lift method is new to these producing basins, there is often a lack of local expertise needed to support such systems. Although gas lift may be relatively immune to the previously mentioned operational challenges, it generally provides less drawdown than what might be achieved with an optimally sized pumping system. If I sound overly pessimistic about the prospects for artificial lift in unconventional wells, I’m actually not. Engineers thrive when they have challenging problems to solve, and unconventional resources provide artificial lift engineers with ample opportunities for innovation. In recent years, I have witnessed a windfall of new technologies, including improved electrical-submersible-pump stage design, the use of permanent magnet motors, improved downhole gas-separation techniques, tailpipe systems for slug management, a variety of new automation techniques, surface-controlled gas lift valves, modular high-pressure compression systems, novel downhole completion designs, and more. I am thrilled with the array of new artificial lift technologies that the unconventional revolution has prompted, and I can’t wait to see what the future holds. Recommended additional reading at OnePetro: www.onepetro.org. SPE 194396 Downhole Gas Separation in a High-Gas/Liquid-Ratio CO2 Application by B.L. Nicholson, Occidental SPE 196146 First Digital Intelligent Artificial Lift Production Optimization Technology in UAE Dual-String Gas Lift Well—Business Case and Implementation Plan by Ahmed Alshmakhy, Abu Dhabi National Oil Company, et al. SPE 194408 Electrical Submersible Pump Powered Injection Systems Enable the Development of West-of-the-Nile Egypt Assets by Miguel Munoz, Qarun Petroleum, et al.

A Method for Diagnosing Formation Fluid Leakage During the Operation of Sucker Rod Pumps and a Device for Its Implementation

The operation of oil sucker rod pumps (SRP) is known to be one of the most common and basic methods of oil production, especially for marginal wells. However, rapid wear of the plunger pair, tubing and sucker rods caused by friction, leading to a decline in equipment performance, as well as to labor intensity of replacement and repair of deep-well pumps, determines the relevance of developing methods for diagnosing the technical condition of sucker rod pumping units (SRPU) and formation fluid (FF) leakage during the operation of SRPU as an indicator of the technical condition of SRPU in particular. As one of the controlled parameters, leakage value is important for the operational control of well performance and increasing the efficiency of oil production. The authors consider the impacts of well product leakage both in the pump itself (the “cylinder-plunger” clearance, valves) and on the path of the pump product from the cylinder to the orifice (through threaded connections of the tubing string (TS) of the well, through possible pipe breakdowns caused by wear due to rubbing against the rods, etc.). In the existing literature, formulas are given for calculating the amount of fluid leakage through the clearance between the working surfaces of the plunger and the cylinder of a SRP during laminar flow in the clearance (laminar regime is the most probable), with the clearance as the main parameter, cubed. However, this formula requires determining the size of the clearance directly, which is an extremely difficult (impossible) task in an operating SRPU. And results of determining leakage from dynamometer cards and piezograms have low accuracy. In view of the above, the paper proposes a new method and a device for its implementation, which involves measuring the pressure on the well flow line and at two points of the tubing string (TS) of the well, one of which is located at the TS orifice, and the second lower at a distance of half the height of the cylinder of the pump being used, the FF leakage from downhole pumping equipment being calculated by the algorithms given in the text. It is shown that the proposed diagnostic method makes it possible to more accurately and reliably, in comparison with the existing methods, determine the formation fluid leakage during the operation of SRPU.

Statistical analysis of the failure times and feed rates of downhole pumping equipment in operating parameter ranges

Statistical analysis of the failure times and feed rates of downhole pumping equipment in operating parameter ranges

Analysis of the use of downhole pumping equipment (DPE) at the Tevlinsko-Russkinskoye field

The problem of operating ECP in the zone of low production rates is very relevant for a number of leading oil companies, since most of the wells are operated by such pumps. The adopted values of the boundaries of the working part of the characteristics of the pump are indicators: 0.75–1.25. According to preliminary estimates, 31 % of the ECP at the Tevlinsko-Russkinskoye field are operating outside the operating range, which leads to a decrease in the operating efficiency of downhole pumping equipment (DPE). The average well production rate for oil was 8.6 tons per day, for liquids – 89.5 tons per day, for water content – 90 %. This article presents an analysis of the ECP operation in the Tevlinsko-Russkinskoye field. The work describes the complications of the DPE when it is used beyond the right and left borders of the working area. On the basis of pilot field works, the possibility of using alternative DPE has been described. At the end of the article highlighted the main problems relating to the operation of wells and equipment.

АНАЛИЗ ОТЛОЖЕНИЙ НЕОРГАНИЧЕСКИХ СОЛЕЙ В СИСТЕМЕ СБОРА НСП «Б», ДНС-5 «А»

Актуальность. В настоящее время проблема образования отложения солей очень актуальна и важна. Добыча нефти затрудняется с появлением неорганических отложений, которые образуются в призабойной зоне скважин и в системах сбора и подготовки скважинной продукции. Последствием отложения солей является снижение коэффициента продуктивности скважин, из-за чего происходит значительная потеря нефти. Также по причине недостаточного притока возникает риск отказа глубинно-насосного оборудования, происходит снижение наработки на отказ этого оборудования из-за того, что возникают заклинивания электроприводного центробежного насоса и клапанов штангового глубинного насоса. По этим причинам нефтяные компании терпят значительные убытки, так как возникает необходимость больших затрат на мероприятия по предупреждению и борьбе с солевыми отложениями. Цель. Определить методы предупреждения отложений и методы борьбы с ними. Выяснить будет ли выпадать осадок в результате определения коэффициента пересыщения φ по методике Скилмена–Мак-Дональда–Стиффа. Провести анализ исследований по определению компонентного состава отложений. Методы. При проведении расчетов использовалась методика Скилмена–Мак-Дональда–Стиффа. Неорганическая часть отложений определялась методом рентгеновской дифрактометрии на порошковом дифрактометре Shimadzu ХRD-6000. Результаты. Анализ результатов определения макро- и микрокомпонентного состава вод показал, что в пробах попутно-добываемых вод, отобранных с добывающих скважин и автоматизированные групповые замерные установки месторождения Х, содержится существенное количество ионов кальция и сульфат-ионов, что может привести к образованию отложений нерастворимых солей, таких как кальцит и гипс. В скважинах под номерами 5 и 311 коэффициент пересыщения φ>1 (существует пересыщенность пластовой воды гипсом). В этих скважинах гипс имеет возможность выпадать и в объеме, и на самой поверхности теплообмена. В скважине под номером 158 коэффициент пересыщения φ<1. При ненасыщенности им пластовой воды выпадение осадка в объеме не будет. Однако на поверхности теплообмена, вследствие частичного выпаривания раствор особо насыщается гипсом. Из-за этого гипс способен откладываться и при некоторой недонасыщенности им пластовой воды – при понижение коэффициента φ до 0,9. Чтобы отложения гипса не осложняли добычу нефти, нужно заранее предупреждать образования отложений. Для предотвращения образования отложений необходимо подобрать эффективный ингибитор солеотложений для условий месторождений, осуществляющих сбор на НСП «Б». С целью защиты системы нефтесбора рекомендуется организовать подачу ингибитора солеотложений.

ABOUT MICROBIOLOGICAL CORROSION AT OIL FIELDS IN WESTERN SIBERIA

Background Operation of the most oil fields late stage of development leads to an increase in the number of complications associated with the oilfield equipment corrosion. One of the reasons for the spread of corrosion is the presence of sulfate reducing bacteria in the production of wells. A laboratory studies have shown that the corrosion rate in reservoir water containing even a small concentration of sulfate reducing bacteria is 10-12 times higher than in formation water that does not contain sulfate reducing bacteria. Aims and Objectives o analysis of corrosion processes of oil field and downhole pumping equipment; o on the basis of field data from the Pokhovsky and Vatyegansky fields, operating by OOO Lukoil-Western Siberia, to prove the optimal method for preventing corrosion processes in oilfield equipment. Results On the basis of wells data of the Lukoil-Western Siberia LLC, it has been established that sulfate-reducing bacteria presents in about 40 % of the produced water samples. The best method of preventing salt formation and corrosion is the injection of multicomponent synergistic and multifunctional compositions into the bottomhole formation zone and the annular space of wells, which are selected on the basis of timely analysis of failures of downhole pumping equipment and laboratory tests.

THE RESEARCH OF PETROLEUM JET PUMP OUTLOOK

The development trends of hydraulic jet pumps used for the oil-fields exploitation are analyzed. The ambitionto optimize the process of mixing flows has led to the emergence of numerous designs of jet pumps, in which swirling flows are used instead of direct flows. The creation of circulation flows in the pump wet end promotes alignment of coaxial flows velocities, intensifies the process of energies exchange in the liquid, and increases the efficiency of the mixing process. The combination of direct and circulation flows gives a possibility to improve the technical characteristics of jet pumps up to 30%. The dimensions and the mutual orientation of the elements of the pump wet end have a decisive influence on the energy efficiency of the ejection technologies implementation. The optimization of dimensions and orientation of the components of the jet pump necessitates multifactorial experimental studies, which, in addition to the design factors, should also take into account the working mode of the ejection system in the well. The task of optimizing the design and mode parameters of a well ejection system can be solved by simulating the work process of the jet pump using modern software complexes Solid Works and ANSYS, which provide the necessary accuracy of the calculation operations. The efficiency of the ejection system also depends on the depth of its location in the well. Determining the optimum depth of installation of the ejection system in the well presupposes the use of iterative calculation methods with the aid of appropriate computer programmes (for example, Matchad). The development of the hydro-jet operation of oil wells is characterized by the tendency of a joint arrangement of the ejection system and traditional types of downhole pumping equipment. In the design of the combined oil-producing system the jet pump creates a low pressure zone in the bottom and intensifies the inflow ofhydrocarbons from the production horizon, while the traditional downhole pump transports them to the surface. The presence of an additional (jet) pump in the well optimizes the conditions of the main pump use. It improves the energy characteristics of the bottom-hole assembly and increases the efficiency of oil production. The analysis of the hybrid ejection technologies application indicates the prospects of this trend of oil and gas equipment.

Multiphase gas compression to boost unconventional production and reserves

Hydraulic fracturing has significantly increased well inflow performance in unconventional reservoirs, enabling their economic development. This improved inflow performance has opened up the possibility of leveraging further reserves and production gains through artificial lift or similar production enhancement techniques. A ‘multiphase compressor’ has been developed with differentiating characteristics:compression ratios of up to 40:1 (an order of magnitude greater than conventional compressors), ability to handle a broad range of multiphase conditions, and significant operational flexibility. This makes it very well suited for deployment in unconventional reservoirs at the wellhead, either on its own in a multiphase boosting capacity or in conjunction with other forms of artificial lift (such as gas lift, plunger lift, and potentially downhole pumping). The multiphase compressor has been deployed in the field on naturally flowing wells, and wells with plunger lift. Production rate increases of up to 300% were achieved, and production was maintained in wells that would have otherwise loaded up and died. Wells were unloaded by reducing wellhead flowing pressures to atmospheric pressure at the compressor suction – similar to flowing the well into an ‘open topped’ tank. The multiphase compressor demonstrated a very broad operating range and the ability to handle slug flow conditions. Further applications to be tested include gas lift and downhole pumping in shale wells, gas wells that have received fracture hits and require clean up from invaded fracture fluids, and coal seam gas production. Multiphase compression has significant potential to increase both production and reserves from unconventional reservoirs and wells.

Diagnostics of the condition of sucker-rod pumping units after the analysis of dynamogram cards

Despite of the increased share of oil wells equipped with submersible electrical centrifugal pumps, a considerable part of them is equipped and operated with sucker-rod pumping units. When operating wells with sucker-rod pumping units, different plunger pumps are used. The rod string is operated in severe environment due to long contact with highly corrosive well products and time-variant loads. Taking into account all acting loads, the diagnostics of the condition of sucker-rod pumping units is a difficult task. At the majority of oil fields in Russia, the operation of wells equipped with sucker-rod pumping units is controlled by portable and stationary dynamographs of various models. Moreover, dynamographs are used, as a rule, only to obtain images of dependence of the force on the polished piston rod upon its stroke. Based on dynamograms it is possible to find the well flow rate, pump capacity, force on the polished piston rod, etc. But one of the main problems to be solved with the help of dynamometry is the forecasting of down-hole equipment condition in the process of further operation. In this paper we overview the methods to diagnose the condition of sucker-rod pumping units based on dynamograms. The aim of the work is to develop the mathematical model to forecast the failures of down-hole pumping equipment on the results of dynamometry to automatize the control process of the unit operation. The research tasks are to analyze the existing methods for diagnosing the condition of sucker-rod pumping units, and to develop the mathematical model for forecasting the failure of the valve unit leakage. As a result, the method for forecasting the increased failure on the example of the fluid leakage in the pump injection unit is proposed. The permissible boundaries of the change in the relative force on the polished piston rod are drawn up. As a result, the failure increase is forecasted based on the frequency of the relative force on the polished piston rod getting within the interval obtained.

Technology Focus: Artificial Lift (July 2018)

Technology Focus One of the more exciting aspects of artificial lift is the constant influx of new technologies and new ideas that the discipline invites. Inventors appear to be regularly developing “the next new thing” in artificial lift. Some ideas are so brilliant and so obvious, you ask yourself, “Why didn’t I think of that?” Other ideas seem so zany and so ill-conceived, you ask yourself, “What were they thinking?” In every case, these new technologies have the same goal: To produce more oil and gas more reliably and more cost-effectively. One of my artificial-lift mentors has such a long history of developing and championing new downhole pumping technologies that he once described his career as the “relentless pursuit of the everlasting pump.” Even in retirement, he continues this lifelong passion. Yet, it occurs to me that the everlasting pump may actually exist today—through the correct application of field-proven technology. Although we seem to have a never-ending supply of new artificial-lift technologies, the technologies that consistently allow us to achieve our technical and business goals are usually the old ones. There is a catch, however: You need to apply those technologies correctly. Applying artificial-lift technology correctly means selecting the right lift method in the first place, selecting the right system components, installing the equipment correctly, performing effective surveillance, and performing root-cause failure analysis so that we can learn from our mistakes and enable continuous improvement. All of this requires a coordinated effort, not just between vendors and operators but also between the various groups within the operating companies themselves. Each of these groups has a stake in the success of the well and should be aligned around a common set of goals to ensure that the artificial-lift system performs reliably and delivers optimal production and does so in a cost-effective manner. All of the papers selected for this section concern the correct application of field-proven artificial-lift technology. Paper SPE 181216 describes the surveillance methods used by one operator to improve the reliability and performance of their beam pumping systems. Paper SPE 186254 describes a method to deploy electrical submersible pumps in gassy horizontal wells to improve gas handling and mitigate slugging. Paper SPE 186110, written by one of our recent Legends of Artificial Lift inductees, provides new insights into the application of injection-pressure-operated gas-lift valves, to allow operators to improve the design and overall reliability of gas-lift installations. To see more great artificial-lift papers like these and to welcome our latest class of Legends, I invite you to join us for the 2018 SPE Artificial Lift Conference and Exhibition—Americas on 28–30 August 2018 in The Woodlands, Texas, USA. Recommended additional reading at OnePetro: www.onepetro.org. OTC 28123 A Step Change in Safety and Quality for ESP Deployment in the North Sea by L. Pastre, Schlumberger, et al. SPE 190090 Detecting Failures and Optimizing Performance in Artificial Lift Using Machine Learning Models by Mike Pennel, OspreyData, et al. SPE 187490 A Novel Approach to Distributed Field-Based Gas-Lift Facilities by Siddharth Mullick, Anadarko Petroleum, et al.

Artificial-Sump-Pumping System Improves Production in Unconventional Oil Wells

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 186254, “Improve Production in Unconventional Oil Wells Using Artificial-Sump-Pumping System,” by Reda Elmahbes, Regulo Quintero, and Agnetha Evelyta, Baker Hughes, a GE Company, prepared for the 2017 SPE/IATMI Asia Pacific Oil and Gas Conference and Exhibition, Bali, Indonesia, 17–19 October. The paper has not been peer reviewed. Unconventional oil wells present challenges to electrical-submersible-pump (ESP) systems and can limit production potential. An artificial-sump-pumping system used in unconventional oil wells with steep decline curves and high amounts of free gas has been shown to operate reliably and economically. This paper presents a comparison of conventional ESP methods and artificial-sump systems for which free gas and gas slugs are a challenge. Introduction Unconventional oil wells usually have inadequate reservoir permeability. To enable a significant amount of fluid flow from the reservoir to the wellbore, the wells are drilled horizontally and multistage hydraulic fracturing is performed to expose as much reservoir to the wellbore as possible. The long horizontal laterals create unique production challenges. As the reservoir pressure declines in unconventional reservoirs, gas is released from the fluid and accumulates in hump undulations of the horizontal section. When the gas slugs break free, they create cycling and gas locking that has a negative effect on system performance and reliability. Repeated shutdowns because of gas locking have a negative effect on the production and longevity of the artificial-lift system. Reducing the running time for an artificial-lift system can significantly increase operator capital and operational expenses (OPEX). Some gas slugs can be very large and can create a low-flow or no-flow condition that is challenging for most artificial-lift systems. Therefore, gas slugs must be separated from the liquid before entering the downhole pump to improve production and enhance artificial-lift-system reliability. Designing a system that can avoid slugs and prevent excessive amounts of gas from entering the downhole pumping system is crucial to produce economically from unconventional oil wells. Artificial-Sump-Pumping System An artificial-sump-pumping system is a new form of gas mitigation that uses an ESP artificial-lift method with an inverted shroud that surrounds the entire system. The ESP is equipped with a recirculation system to keep the ESP motor cool during slugs. In addition, the fully encapsulated system has enhanced motor-lead-extension (MLE) protection that helps avoid cable damage during run in hole (RIH), especially for 5½-in.-casing applications. This solution is mainly used for wells that are very gassy and have the potential for gas slugs. Fig. 1 shows a schematic for an artificial sump with a recirculation system. Optional components are recommended to be used on the basis of well conditions and fluid characteristics. For instance, a sand-control system is recommended for applications where sand and abrasive risk is high.

Technological Efficiency of Implementation of Dual Completion of Objects

Нефти Удмуртии характеризуются как трудноизвлекаемые, с повышенной вязкостью, высоким содержанием парафина и смол. Большинство разрабатываемых месторождений ОАО «Удмуртнефть» на сегодняшний день находятся на третьей и четвертой стадии разработок. Характерными особенностями данных стадий разработок является высокий темп снижения добычи углеводородов и значительный рост обводненности скважинной продукции. Для увеличения объемов добычи предложена технология одновременно-раздельной эксплуатации объектов добычи нефти (ОРЭ). Внедрение ОРЭ позволит: подключить другие объекты пластов за счет уплотнения сетки без бурения дополнительных скважин и повысить рентабельность добычи; вести раздельный учет добычи нефти по каждому пласту. В работе выявлены критерии эффективности применения технологий одновременно-раздельной добычи нефти глубинно-насосным оборудованием на месторождении ОАО «Удмуртнефть» с высоковязкими нефтями; предложена оценка технологической применимости ОРЭ на месторождении, проведены расчеты технологической эффективности внедрения технологии одновременно-раздельной эксплуатации объектов добычи нефти на месторождении. Доказана целесообразность ее внедрения.