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1 SPE Artificial-Lift Operation Technologies of Low-Pressure Flooded Gas and Gas-Condensate Wells A.N. Drozdov, SPE, G.G. Bulatov, A.N. Lapoukhov, E.A. Mamedov, E.A. Malyavko, SPE, and Y.L. Alekseev, SPE, Gubkin Russian State University of Oil and Gas Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPETT 2012 Energy Conference and Exhibition held in Port of Spain, Trinidad, June This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract One of the main reasons, leading to the production decline of gas and gas-condensate wells is the accumulation of liquid fluid on the bottom of the well and formation of liquid blockage. Under certain conditions, bottom hole pressure drops, flow rate declines and gas velocity reduction becomes insufficient for the liquid lifting. Periodic gas purging of low-pressure wells practiced in Russia for water extraction, leads to the unproductive losses of hydrocarbons and forbids achieving stable operation. It leads to the retirement of wells out of the producing well stock, formation of dead zones with entrapped gas and, as the final result, to the waterflood hydrocarbon recovery drawdown. This problem can be solved by putting low-pressure flooded wells on pump, as international experience being indicative of its benefits. Various engineering solutions based on the field tests of the techniques, mentioned above, were examined. The most suitable and viable technologies, for one of the Russian fields to be at the latest stage of reservoir development, were electric submersible centrifugal pumps (ESP) and electric progressive cavity pumps (ESPCP): with the removing of water to the surface and the subsequent injection of water into injection wells, and also with the injection of water into the underlying aquifer in the existing producing well. We developed a rational method of hydraulic calculation and selection ESP and ESPCP for different operating conditions. Preliminary bench experiments of ESP s, centrifugal gas separators and separator of mechanical impurities were carried out. The equipment has proven its efficiency. The proposed solution will ensure the efficient functioning of the system of artificial-lift gas and gas-condensate well operation without using the unique expensive equipment. Also in a short period of time it could allow adapting the quantity produced submersible pumps for the conditions of gas industry. Introduction For many oil-gas-condensate fields, being developed in a significant reduction in bottom-hole pressure, flow rate and gas velocity, the nagging problem is liquid accumulation on the bottom. Moreover, the major part of deposits is developed under conditions of elastic water drive; operation of such wells is considerably complicated by the flooding, and this problem becomes more nagging every year. Regimes and the type of fluid flow in the tubing are changing, the formation of liquid blockage occurs, which, in turn, leads to a decrease of well workability and production loss (go-off). As a result, more and more wells are being taken out of service due to flooding before their potential reserves are depleted. Periodic gas purging of low-pressure wells practiced in Russia for water extraction, leads to the unproductive losses of hydrocarbons, forbids achieving stable operation, results in the destruction of well-bottom-zone rock and the abrasion of equipment and negatively affects the ecological state of the environment. Frequent well shutoffs and slow development of the reserves in the flooded areas lead to the formation of dead zones and, consequently, entrapped gas. All this does not allow us achieving high hydrocarbon recovery. The relevance of the gas well flooding problem in fields being developed on the final stage The authors analyzed the information on the current status of wells and production performance using them on a number of fields where the work is complicated by the simultaneous presence of several phases in the fluid. Most attention in the research was focused on the features of the development of gas deposits of one of the largest oil-gas-condensate fields, as it is

2 2 SPE a typical example of an object, in which gas production is complicated due to a significant drop in reservoir pressure (up to 80-90% of initial value), in gas flow rate and also due to flooding and self-killing. The gas fields mentioned above include more than 700 wells, which technical condition has become much worse for the last 2-3 decades. This creates barriers for achieving satisfactory performance of water shutoff operation in the wells. However, the degree of importance of the use of efficient operating technologies in the current complicated conditions may reflect the following facts: - actively growing number of inactive wells and percentage of killed (because of flooding) wells (86%); - growing number of gas wells, working with the removal of the formation water according to the results of hydrochemical monitoring; - growing specific content of the liquid in the produced gas; - rate of rise of gas-water contact is 1-3 m/year; - number of wells, which don t provide removal of liquid by the gas flow, has been steadily increasing. There have been known quite a number of methods for calculating the minimum allowable gas flow rates providing the removal of the liquid from the bottom of the well. Most of them are based on empirical curves describing with sufficient accuracy the processes taking place only under certain circumstances. By the previous comparative analysis we found [1] that for similar operating conditions they are the film gas-liquid mixture flow model for vertical pipes (criteria of Tochigin and Kutateladze) and the empirical formula obtained by V.N. Gordeyev which describes the well performance most correctly. According to this method, the value of the minimum flow rate required for the removal of liquid from the well can be calculated with the following formula: gσρ Q = 3,3 ρ (ρ ρ ), πd 4 P P T ZT 86,4, (1) where Q - minimum required gas flow rate (m 3 x 10 3 /day); ρ and ρ - density of liquid and gas respectively (kg/m 3 ); σ - surface tension coefficient for water under P and T (N/m); D - internal diameter of the production tubing (m); P, T - working temperature and pressure (MPa, K); P 0, T 0 standard pressure and temperature; Z - real gas factor under P and T. The correlation, which is designed by Turner, etc., became very popular in the global gas production experience and it is used to determine the minimum velocity which would provide the removal of liquid (water) out of the well. This formula is: V = 4,43 (67 0,00279 P Z ), (0,00279 P Z ),, (2) where V minimum speed, required for the removal of water out of the well, fps; P - working pressure, psi. In addition, the corresponding minimum flow rate required for the removal of the liquid out of the well is given by: Q = 3,067PV A (T + 460)Z, (3) where Q - the minimum required gas flow rate (MMcfd); A = πd 2 /576 - cross-sectional area of the space inside the tubing; D - internal tubing diameter, inch; P, T - working pressure and temperature, psi and F [6]. The Turner s function, mentioned above, is obtained for surface tubing pressure in excess of 1000 psi, which corresponds to atm. For the considered case (at lower pressures) Coleman s formulas may be more acceptable. Essentially, the formulas proposed by Coleman (for low pressure) are identical to Turner s ones, but they do not contain an empirical correction factor, which was used by Turner to adapt the correlations to the actual data. Coleman s equation for determining the minimum gas velocity for the removal of liquid (water) out of the well is as follows [6]: V = 1,593σ, (ρ ρ ), ρ,. (4) In accordance with the methods of determining the minimum velocity of the flow and flow rate required for the removal of water out of the wells (by Tochigin, Turner and Coleman) we calculated and analyzed the results in order to identify wells in which the existing technology of production cannot ensure the removal of liquid. The equations contain empirical coefficients that allow adapting the results of the calculation to the actual situation on the removal of liquid from the well. They are not completely accurate, the researchers argue that the deviations from the fact may

3 SPE be as high as 20%, but for evaluation purposes, they can be applied. The comparative analysis was performed by three methods to improve the accuracy of the results. There have been found that the most stringent requirements to ensure conditions for the removal of liquid follow from the results of calculations by the Tochigin s method, therefore, we paid special attention to these results. In addition, the reserve coefficient k z = 1.20 was established on basis of expert evaluation. This coefficient corrects the result on the higher-value side. The main results of the analysis stated below: - percentage of the current producing gas well stock, in which the liquid is not removed with the gas flow, is 8%; - more than 51% of the wells, in which the liquid removal with the gas flow does not occur, work with flow rates, m 3 x 10 3 /day less than the minimum required flow rate (which could provide the removal of liquid with the gas flow). The traditional gas well operation under such complicated conditions involves the termination of gas production at the moment of self-killing when the reservoir still contains a significant amount of reserves. For this reason, the introduction of the technology, that allows extending the service life of existing well stock and increases the ultimate gas recovery, is very important. Artificial lift technology for the operation of low-pressure flooded gas and gas-condensate wells To date, there are many engineering solutions on the flooded-gas-well operation, among which there are the use of surfactants, the use of smaller diameter pipes, plunger lift technology, gas lift technology, pump and compressor operation methods, etc. In the various operating conditions these solutions may have different performance. For the conditions of a Russian oil and gas field (Cenomanian), the authors conducted a technical and economic analysis of the applicability of these technologies. The main technical requirements for the technologies were the following: - features of low-pressure gas production from flooded cenomanian gas wells on the late stage, taking into account physical and chemical properties of the products; - work in conditions of sand production; - downhole separation of liquid and gas; - injection of the liquid into the underlying aquifer (in suitable geological conditions) or in the absorbing well in a cluster; - use of isolated generating plant for electricity generation using gas, extracted from the existing wells in the field; - no construction of additional transmission lines and extended water pipelines; - prevalence of the considered equipment on the Russian market. The results showed that the most preferred technology was artificial-lift operation, namely the use of ESP and ESPCP. The increase in production due to equipping wells in accordance with the technology of artificial lift is expected as the result of the removal of liquid from the flooded well and elimination of the propensity to self-killing, as well as the result of extending the life of the wells. From this perspective, the ESP and ESPCP technologies are similar - their effectiveness is due to the same factors. For the actual process of gas production a choice between ESP and PCP is not very important. Preferences may be based only on indicators of energy intensity, MTBF, etc. It is therefore important to make a comparison of field performance in the traditional version and version, implying the introduction of artificial lift. Such a comparison has been made on a large field, described above. On the basis of the known geological and production data we carried out an estimating predictive modeling of technological field development performance in two ways: the traditional operation and artificial-lift operation of flooded gas well. With the use of methods of prediction of field performance for the water drive, which is based on the theory of the enlarged well of Van Everdingen & Hurst, we evaluated the expected amount of additional gas. It averaged 30 m 3 x 10 3 /day per well out of modernized well stock (of 80 units) (Fig. 1). This assessment includes the technological risks associated primarily with the modeling assumptions (averaging reservoir parameters, neglecting inhomogeneities, etc.) and identifies the feasibility of further more detailed study of the artificial lift operation. World experience clearly demonstrates the benefits of the putting of low-pressure gas wells on pump. Experience of development and commercial application of this equipment in Russia is also important. In particular, field tests have been carried out and now centrifugal gas separators, dispergators and centrifugal solids separators are commercially produced [3]. This allows adapting the commercially produced equipment for the operating conditions of flooded low-pressure gas wells in a short period of time. At the Russian gas fields, in contrast to oil fields, in many cases there is no appropriate infrastructure for the transportation and disposal of produced water. The wells are located far from the infrastructure and they are not electrified. Therefore, the Gubkin Russian State University of Oil and Gas proposed to produce electricity on the well cluster [2]. Various schemes of artificial lift can be used, depending on the geological conditions and the properties of the extracted product. Downhole separation of gas and liquid can be carried out by the gravitational method (with a pit), and with the help of centrifugal gas separators. We also should use a solid separator when the presence of a high proportion of solids. In the wells with production casing leaks, as well as when the downhole products are very aggressive and corrosive it is necessary to run dual-string lift with pumping liquid through an internal tubing, and gas - through the annulus between the outer and inner tubing.

4 4 SPE Fig. 1 - Dynamics of average daily gas flow rate (including forecasts up to 2025) A plunger pump with a linear permanent magnet motors and a single-wire supply line has huge potential. The development of this system has already begun. Innovative solutions will improve the energy efficiency of liquid pumping with low flow rates. The projected efficiency of the system should reach 55.9%, and the increase of mean time between failures comparing to ESP should be more than 10%. The development of rational selection and calculation method for ESP and ESPCP under various operating conditions The principal technological schemes for the calculation of the hydraulic system, "reservoir a production well equipped with an ESP a surface pipeline - an injection well an intake bed" are presented in Fig. 2 and Fig. 3. In both cases, water from the production wells is delivered to the surface and injected into the absorbing well. Fig. 2 shows the production well 2, draining the reservoir 1. The ESP is attached to the inner tubing 3. The main elements of the ESP unit are a submersible electric motor 5, a centrifugal gas separator 6, which separates the gas and sends it to the annular space, and the ESP 7, which pumps water. Thus, gas is produced through the annular space; water is lifted to the surface through the tubing and injected in the intake bed 14 through the common injection well 11. The injection well is equipped with a packer 13. Fig. 3 shows similar production well 2, draining the reservoir 1. The ESP is attached to the inner tubing 3. The main elements of the ESP unit are the ESP 7 and a submersible electric motor 5 with engine casing 6, which plays a role of the gravitational separator, protecting the motor from overheating at the same time. In this case, gas is also produced through the annular space of dual-string lifting system; water is lifted through the internal tubing to the surface and injected in the intake bed 14 through the common injection well 11. The injection well is equipped with a packer 13. Point A (the output of ESP), B (the beginning of the surface pipeline going to the injection well), C (the bottom of the injection well) - the characteristic points of the hydraulic system. It should be noted that the ESP system can be equipped with a submersible solid separator (not shown), but the calculation method will be the same. Also, the assumption of this method is 100% downhole gas separation. In the flow chart shown in Fig. 2, this is achieved by high-performance of water-gas separator due to the low foaminess of water. According to our bench tests described below, the separation coefficient of the centrifugal gas separator when separating coarse-dispersion gas-liquid mixture with low foaming properties is close to 1. The residual gas content of gas-liquid mixture flowing into the pump also does not have a noticeable effect on the operating parameters of the pump.

5 SPE Fig. 2 - Basic diagram for the hydraulic design of the system with the removal of water up to the surface by the ESP equipped with the gas separator: 1 reservoir; 2 - production well; 3, 4, 12 - tubing, 5 - ESP submersible motor; 6 - gas separator; 7 ESP; 8 - dynamic level; 9 - surface pipeline from the producing well; 10 - lead pipeline for water injection in the injection well; 11 - injection well; 13 packer; 14 intake bed Fig. 3 - Basic diagram for the hydraulic design of the system with the removal of water up to the surface by the ESP, lowered below the perforation intervals and equipped with the engine casing: 1 reservoir; 2 - production well; 3, 4, 12 tubing; 5 - ESP submersible motor; 6 engine casing; 7 ESP; 8 - dynamic level; 9 - surface pipeline from the producing well; 10 - lead pipeline for water injection in the injection well; 11 - injection well; 13 packer; 14 intake bed

6 6 SPE In the flow chart shown in Fig. 3, this assumption is valid due to the high efficiency of the gravitational separation by the engine casing. In this case the maximum diameter of the casing is chosen to make the drift velocity of the gas in the liquid flow equal to zero: w. = w w, (5) where w true gas velocity; w - true liquid velocity. Thus, as the well fluid is usually reservoir and/or condensed water with small dissolved gas content, the real characteristics of the pumps are close to the passport ones. It is obvious that when using progressive cavity pumps instead of ESP the presented flow charts as well as the selection method itself are not changed fundamentally. The calculation method is simple and is based on the hydraulic laws: 1. Let us calculate the Reynolds number, the coefficients of hydraulic friction and the flow regimes in the characteristic points of system - A, B and C. 2. Let us calculate the total hydraulic losses in the section A-B and B-C, which consist of friction and form losses. As calculation of the form losses in this case is difficult, we assume that the total loss is equal to 1,1 multiplied by the friction losses: h = 1,1 λ L. D. V L 2g + λ V D 2g = 8,8Q π g λ h = 8,8Q. π g L λ D + λ L. D. L. D. L + λ, (6) D, (7) where, λ - hydraulic losses in the points A and B; L., L. - length of the tubing in the production and injection wells; V, V liquid velocity in the points A and B; Q, Q. - flow rate in the production and injection wells; L, L - the length of the surface pipelines (Fig. 1, 2). 3. Let us determine the bottom-hole pressure, which provides the required water flow rate for the injection well: p.. = p.. + Q. λ, (8) where p.. reservoir pressure in the injection (absorbing) well; λ hydraulic resistance of the intake bed in the injection well. 4. Let us write the Bernoulli equation for the section A-B and B-C: z + p ρ g + α V 2g = z + p ρ g + α V 2g + h, (9) z + p ρ g + α V 2g = z + p ρ g + α V 2g + h, (10) where z, z, z depth of the section A-A, B-B, C-C; p, p, p absolute pressure in the sections A, B and C, respectively; α, α, α - kinetic energy coefficient; for the turbulent flow equal to 1. Using Eq. 5 we determine the minimum pressure needed for the injection of the fluid with the required flow rate in the injection well. If the value p turns negative, it indicates that the intake capacity of the absorbing bed is sufficient to ensure that the liquid flows into the well by gravity. In this case, the value p should be set equal to the minimum allowable pressure in the surface pipeline. Using Eq. 6 we determine the pressure p - the pressure at the outlet of the submersible pump. Knowing the bottom-hole pressure, we determine the pump head and finally select its model. In this case, it is assumed that the pump intake is run to the upper perforations and the pressure at the pump intake is equal to the bottom-hole pressure. However, if it is not so (as, for example, in Fig. 3), the described method would be the same. This is due to the fact that the pressure loss in fluid flow along the length of the pump is not considered. Pressure loss in fluid flow along the length of the tubing, which is equal to the difference between the bottom and the pump outlet, can be also neglected because of its smallness. Thus, the "actual work" of the pump would consist in the lifting fluids from the depth (equal to the dynamic level) to the surface. The flow chart for the calculation of the hydraulic system "reservoir a production well equipped with an ESP an intake bed," is shown in Fig. 4, which shows the well 2, draining the reservoir 1. The ESP is attached to the inner tubing 3. The main elements of the ESP unit are a submersible electric motor 7, a centrifugal gas separator 6, which separates the gas

7 SPE from the liquid, and the ESP 8. Gas goes to the production tubing; water goes to the annular space by means of which we create hydraulic lock, preventing gas entering the pump 8. Thus, gas is produced through the annular space and the inner tubing; water goes to the intake bed 10. The well is equipped with a packer 9 and its dynamic level is 5. The points A (ESP outlet) and B (upper perforation of the intake bed) are the characteristic points of the hydraulic system. All the assumptions made in the calculation in the previous flow chart are valid here. The method of hydraulic calculation for this case is identical to the previous one, and it consists in the sequential determination of the coefficients of hydraulic resistance and flow patterns at characteristic points of the system, the calculation of pressure losses in each of the sections, required bottom-hole pressure when injection in the absorbing layer, the pressure at the outlet of the pump and its head. As it can be seen in all cases, the ESP intake is protected from free gas entering. This is achieved through the effective operation of the gas separators, a creation of the the hydraulic lock in the annular space along the body of the gas separator (the gas separator should be designed to make its flow of the flowing channel significantly higher than the well liquid flow rate), and also the effectiveness of gravitational separation of phases. Fig. 4 - Basic diagram for the hydraulic design of the system with the injection of water into the underlying intake bed by the ESP equipped with the gas separator: 1 reservoir; 2 well; 3, 4 tubing; 5 - dynamic level; 6 - gas separator; 7 - submersible motor; 8 - ESP; 9 packer; 10 intake bed Equipping the ESP s with modern intelligent control stations with frequency converters we provide a good adaptation of the pumping systems to the changing and unstable flow of water during operation. In some cases, an intermitting production by ESP is also possible [4]. Bench tests of ESP and gas separator Bench tests of the gas separator GSA5-1 manufactured by "Alnas" were carried out on the water-air mixture produced by using the charge pump and the liquid-gas ejector. Gas separator, together with an electric pump ESP5-125, were placed in a model of the production string and brought into effect by using an induction motor. It should be noted that the gas-liquid mixture "water-air" is coarse-dispersed mixture with low foaming properties, and it fully simulates the reservoir fluid of flooded gas wells. The results of studies [5] are shown in Fig. 5, which presents the dependence of pressure created by the pump (P p ), a liquid flow rate (Q p ), a residual gas content (β res ), a separation factor (K s ) on various input gas content β in. We can see that within the achieved values of the input gas content (β in = 0.49) the effect of free gas at the pump is very small. The reduction of the pump flow is less than 2%; the reduction of the developed pressure does not occur. These studies have reaffirmed the well-known fact that the gas separators for liquid with low foaming properties have a coefficient of separation close to 1.

8 8 SPE Fig. 5 - The dependence of the pump pressure (P p), the pump flow (Q p), the residual gas content (β res), the separation factor (K s) of GSA5-1 gas separator on the input gas content β in on a "water-air" with the initial flow rate Q in= 1.96 l/s [5] Bench and field tests of a solid separator Bench tests of experimental models of submersible solid separator were successful and showed their sufficiently high efficiency. Schematic diagram of the engineering solution is shown in Fig. 6 [3]. However, further field research, carried out in four oil wells, has shown some structural weaknesses of the developed equipment. The objects of testing were chosen out of the frequently repaired well stock, in addition, one of the wells was being developed after the fracturing. The main causes of failure were connected to the overflow of a solids trap and subsequent precipitation of solids on the bottom, which led to a decrease in the liquid flow rate. However, in almost all cases, the results of the commission showed no solid phase at the working elements of the ESP. We also achieved a significant increase of mean time between failures in all wells, and we recovered wells out of the frequently repaired well stock (Table 1). It was possible to increase the mean time between failures in the well «A», and it should be noted that a significant decrease in the number of particles in the fluid sampling occured. For the well «B» it must be noted that pumping unit was shut down periodically due to low productivity of the well. Despite this, when we switched on the pump unit after that, jamming situations did not occur (unlike the standard situation when operation of ESP), which characterize reliable operation of the submersible solids separator.

9 SPE Fig. 6 - Basic diagram of the unit with the submersible centrifugal solid separator [3]: 1 pump; 2 - submersible motor; 3 - centrifugal separator; 4 solids trap; 5 well; 6 rotor; 7 - helical lattice; 8 shaft; 9 coupling; 10 pipe; 11 - perforation interval; 12 reservoir; 13 dib hole; 14 intake; 15 outlet; 16 - offtakes; 17 cable; 18 tubing Table 1 - Comparison of the mean time between failures Well A Well B Well C Well D The field Aganskoe Pokamasovskoje Novo-Pokurskoje Vatinskoe Mean time to failure before the introduction of the solid separator, days Mean time to failure after the introduction of the solid separator, days (after fracturing) - (after fracturing) Well «C» has repeatedly been optimized after fracturing by use of high-performance pumping systems, which led to frequent failures due to clogging of the working parts of the ESP. To protect the ESP the solid separator was introduced. Later it became clear that in addition to the solids trap filling, sump and well perforation interval became overflown by solids, and as a result flow of fluid from the well greatly reduced (from 130 m 3 /day to 63 m 3 /day at the moment of failure). The reason of failure was lack of flow of fluid from the reservoir and, consequently, reducing the electric cable insulation down to zero. The results of the commission disassembly of the pumping unit showed that despite the fact that the solids trap, the upper part of the extension pipe and perforated interval were completely clogged by solids, the elements of the pump and gas separator were worn out just a little and were not obstructed by mechanical impurities. Fracturing was performed in the well «D», after this a submersible centrifugal solid separator in the submersible pumping unit was run for the well development. The reason of failure was the reducing isolation down to zero. In the operation of the well monotonic decrease in performance occurred due to the natural process of removal of solids from the near-well reservoir area after fracturing; some parts of the solid phase accumulated at the well bottom zone, and some - on the bottom of the well. The results of the commission disassembly showed the absence of the solid phase at the working elements of the pumping unit and the solid separator.

10 10 SPE Fig. 7 - Commission disassembly of the separator of mechanical impurities (well «C», Novo-Pokurskoje field) Fig. 8 - Commission disassembly of the ESP (well «C», Novo-Pokurskoje field) At present, the introduction of the submersible centrifugal solid separator extends to various fields of Western Siberia. In the near future we plan to conduct more research in this direction. Additional technology needed to implement an artificial lift Traditional technologies of artificial lift require the well killing and subsequent well development. There have been known the well-killing technologies with self-generating foam systems, killing by the "solid" foam, the use of salt solutions with chemical additives, etc., which have been successfully tested in field. Despite this, the Russian gas companies are not very actively implementing these technologies. Experience shows that the existing low bottomhole pressure and reservoir properties of bottomhole zone cause the risk of a significant reduction in the gas production rate while killing (sometimes it is even impossible to develop the well). In addition we have found out while the analysis of the conditions of a Russian oil-gas-condensate field that problematical flooded wells have a very high percentage of the solid removing. We have carried out the evaluation calculation of the solids trap volume. The initial data for the calculation is presented in the Table 2. Table 2 - The initial data for the calculating the solids trap volume # Parameter Value 1 Gas production rate (in std. conditions) Q g.st, m 3 /day The content of solids per 1,000 cm of gas in std. conditions Q s, gramm/( m 3 x 10 3 ) The average true density of solids ρ s, kg/m The time of the solids trap filling t, years 2 The procedure of calculation was as follows: 1. Let us calculate the amount of solids Q, leaving the reservoir in time: Q g day = Q g 1000 cm Q g Q cm Q day = day 0,001 = ρ 2. Let us calculate the volume of the solid s trap V. : = 34, = 1790 g day, (11) ,001 cm = 7, day.

11 SPE V. = Q cm day t 365 = 7, = 0,523 cm. (12) 3. When an internal diameter of the trap is D=114 mm, the length of the trap L. is: L. = 4V. 4 0,523 πd = 3,14 0,114 = 51,3 m. (13) The existing technical conditions for the wells do not allow lowering the solids traps of such length. Thus, we have revealed a significant criterion, which limits the applicability of the technology. In this regard, we decided to search for other technical solutions which would be more appropriate under these operating conditions. We have found such a solution it is a new technology of artifitial-lift oil and gas well operation without well killing. A distinctive feature of this technology is the use of umbilicals that allow doing round-trip operations without well killing. The ESP will be equipped with ahead labyrinth-helical sections to reduce the harmful effects of mechanical impurities by crushing them. It is also planned to use a linear motor with permanent magnets with the speed 6000 rev/min, thereby we can reduce the length of the submerged part of the unit down to 3-4 meters. The general layout of the equipment, which is run into the well, is shown in Fig. 9. The ESP with the submersible electric motor 4 is attached to the umbilical 3 by a termination (tip) 2. Similarly, the tip 2 is connected to the umbilical hanger on the wellhead 1. At the top flange of the valve there is a blowout preventer with two sets of rams with different diameters. This will allow pressurizing both: along the body of the pump, and along the surface of the umbilical. The umbilical (Fig. 10) contains both hydraulic channels for fluid flow and electrical wires with various cross-sections to power the ESP. It would allow replacing the commonly used steel tubing with an external power cable installation. Umbilical is made on the basis of one segment of steel-polymer pipe 1. To supply the ESP the umbilical contains three power conductors 2 with cross-section from 8 to 16 mm 2. The capillary tube 3 is designed to supply inhibitors to the pump intake. The control conductors 4 are intended for the transmission of telemetry from the ESP and geophysical unit, located under the pump. Fig. 9 - The general layout of the surface and downhole equipment: 1 - christmas tree; 2 - terminations (tips); 3 umbilical; 4 - ESP and submersible motor Fig The design of umbilical: 1 - polymer-steel tube; 2 - electric cable; 3 - capillary tube; 4 - signal wires Conclusion Thus, today there is a wide range of areas in the development of artificial lift technologies for flooded gas wells. The accumulated experience and existing engineering solutions shows that the implementation of these technologies does not cause insurmountable difficulties. It is important that the proposed solutions will ensure the effective functioning of the artificial-lift operation of gas and gas-condensate wells without the use of unique and expensive equipment, as well as adapting commercial submersible pumping equipment for the conditions of the gas industry in a short period of time.

12 12 SPE Nomenclature A = cross-sectional area of the space inside the tubing D = internal diameter of the production tubing, m K s = separation factor L = length of the tubing or surface pipelines, m L s.t = length of the solid s trap, m P 0 = standard pressure, MPa P = working pressure, MPa or psi P p = pump pressure, MPa P bhp.in.well = bottom-hole pressure in the injection well, MPa P res.in.well = reservoir pressure in the injection well, MPa Q = flow rate, m 3 /day Q in = initial flow rate, l/s Q min = minimum required gas flow rate, m 3 x 10 3 /day Q p = pump flow, l/s Q s = amount of solids, leaving the reservoir in time, g/day or cm/day t = time, years T 0 = standard temperature, K T = working temperature, K or F V = liquid velocity, m/s V min = minimum speed, required for the removal of water out of the well, fps V s.t = volume of the solid s trap, cm w g = true gas velocity w g.dr = drift gas velocity w l = true liquid velocity z = depth of the section Z = real gas factor under P and T α = kinetic energy coefficient β in = input gas content β res = residual gas content λ = hydraulic losses λ int = hydraulic resistance of the intake bed in the injection well ρ 1 = density of liquid, kg/m 3 ρ 2 = density of gas, kg/m 3 σ = surface tension coefficient for water under P and T, N/m Acknowledgements The authors would like to thank the deputy director of geology chief geologist of the Gazprom Dobycha Yamburg Ltd. S.K. Akhmedsafin and the deputy manager of Geology, Development and Field Licensing Department of the Gazprom Dobycha Yamburg Ltd. candidate of technique S.A. Kirsanov, and also the director of Pskovgeokabel Ltd. A.V. Robin for supporting this study and sensible advice. References 1. Arkhipov, U.A Improved methods of studing the modes of operation of gas wells. PhD thesis, VNIIGAS, Moscow, Russia. 2. Drozdov, A.N., Ermolaev, A.I., Bulatov, G.G The New Technology of Artificial-Lift Operation of Flooded Gas Wells for the Low-Pressure Gas Production in the Complicated Conditions. Territorija NEFTEGAZ 6: Drozdov, A.N The Technology and Technique of Oil Production by Submersible Pumps in the Complicated Conditions. Moscow: MAKS Press. 4. Drozdov, A.N Artificial-Lift Operation of Low-Pressure Gas and Gas-Condensate Wells. Gazovaja Promyshlennost 644 (special issue): Igrevsky, L.V The Increase of Effectiveness of Pumping-Ejector System Operation for Oil Production. PhD dissertation, Gubkin University, Moscow, Russia. 6. Lea, J., Nickens, H., Wells, M Gas Well Deliquification. Solution to Gas Well Liquid Loading Problems, trans. Moscow: Premium Engineering (2008).