Intermittent Gas Lift Research Articles

Dual Gas Lift in Wells With Downhole Water Sink Completions

Abstract Downhole Water Sink (DWS) technology controls water coning in dual-completed wells by concurrently producing water from the bottom completion below the oil-water contact, and oil from another completion at the top of the oil sand. It has been shown that DWS improves well productivity, increases oil recovery, and could produce oil-free water for direct injection or overboard dumping offshore. To date, DWS has been applied in natural flow wells or wells where a downhole pump can be easily installed. However, in many areas, such as the Louisiana Gulf Coast and Venezuela where water coning is commonplace, the only production method is gas lift. This paper presents a feasibility study and a design method for dual gas lifting in DWS wells. The design employs a two-tier nodal analysis for several combinations of two tubing strings- one for oil and a second one for water-installed in a production casing. First, nodal analysis is performed separately for the water and oil legs in order to define their operational range. Then, the two solutions are combined and coupled with the Inflow Performance Window (IPW) describing the operational domain (top inflow rate vs. bottom inflow rate) of the well. Using the new method, a simulation study was conducted using data from actual wells. The results indicate that the gas lift would limit the performance of DWS wells. Moreover, the design can be optimized for maximum production of oil with controlled water withdrawal from the bottom completion. Limitations such as maximum gas injection rate, or injection gas pressure, are discussed. Also, this paper presents an example of a theoretical performance of a DWS well with gas lift. Dual Gas Lift-State of the Art Gas lift is a flexible method. It is possible to use it in wells of 0.159 m3 (a few barrels) per day, or wells of 159 m3 (a thousand barrels) per day. There are several methods of producing hydrocarbons using gas lift, but continuous gas lift is most common. Presently, there are at least 1,500 wells in Venezuela producing by intermittent gas lift. Also, single well completions are the most used gas lift installations around the world. For any type of gas lift method, there is a maximum production rate, which is a function of depth, reservoir, completion, and surface conditions. This maximum production requires a specific optimized rate of gas injection. Any additional gas injection rate would result in an oil production rate smaller than the maximum rate. To optimize gas lift for a given well, which includes the selection of tubing strings, size limitations, and maximum available gas flow rate, it is necessary to find the best depth of injection point and the gas injection pressure. Although dual gas lift has been theoretically developed, it has not been practiced very much since single well completions are most commonly used around the world. In fact, only a few field cases of dual gas lift have been reported in the literature(1–8).

Intermittent gas lift in Aghajari oil field, a mathematical study

The gas lift is a widely used method of artificial lift, for which there are different options. Previous work in this regard to optimize the continuous gas lift (CGL) of Aghajari oil field located in the south of Iran was promising. A new intermittent gas lift (IGL) simulator is developed considering all aspects of this artificial lift method including the temperature differences between the injected and produced fluids. In order to check the validity of the mathematical model, the intermittent gas lift experimental data, i.e. pressure gradient as a function of time, of Brown [Gas Lift Theory and Practice, Prentice-Hall, Englewood Cliffs, NJ (1967)] were compared with the results obtained by this simulator. The calculated pressure gradient matched well with the experimental data. For the same system, the pressure under the liquid slug as a function of opening pressure of gas lift valve was also calculated and compared with the experimental data. It was found that ignoring the heat transfer between the injected gas and the liquid slug shifts away the calculated results from the experimental points and therefore, decreasing the accuracy of the model. The model then was used to study the Aghajari oil field. The results showed that the production of this oil field will increase significantly using intermittent gas lift method.

Study of the dynamics, optimization and selection of intermittent gas-lift methods—a comprehensive model

The gas-lift is a widely used method of artificial lift, for which there are different design options. There are empirical rules of thumb to choose between the continuous gas-lift (CGL) and the intermittent gas-lift (IGL), but little exists in the literature for the selection among the different intermittent gas-lift designs. Furthermore, computer simulators for these processes usually are not in the public domain. This work presents a numerical model to study the behavior of the Conventional IGL, the IGL with chamber (IGLC), the IGL with plunger (IGLP) and the IGL with pig. Simulations are presented under various reservoir conditions, for different settings of the operation's parameters. The model's results can aid the engineer in the determination of the optimum values of the parameters for each design option and in the choice of the most adequate IGL design for a particular well.

Managing Artificial Lift

Distinguished Author Series Summary The goal of this work is to describe an approach to produce a well for maximum profitability by managing artificial lift effectively. Achieving maximum profitability from an artificially lifted well begins with selecting the lift method and continues with selecting materials, protecting materials, monitoring production data, and monitoring equipment performance. Changes suggested by the monitoring process strive to increase the profitability on an individual well basis. Introduction Managing artificial lift is a continuous process designed to achieve maximum profitability from a producing or service well. We must keep in mind our ultimate goals.Maximum profits, not maximum hydrocarbon production; one does not always mean the other.Maximum profits, not minimum equipment failures; again, one does not always mean the other.Maximum profit within the scope of operating safely and in an environmentally sound manner. The purpose of this paper is to detail an approach to managing artificial lift. This approach is described as a series of steps. Step 1. Original selection of the artificial-lift method. Step 2. Evaluation of production factors and expected production problems. This evaluation results in the selection of the original equipment used in the well, the failure-control methods, and the monitoring deemed necessary for protecting well equipment. Step 3. Continuous monitoring of meaningful production data: rates, fluid levels, water cuts, amp charts, pressures, etc. Step 4. Continuous monitoring of equipment performance data. Step 5. Evaluation of the production equipment-failure data regularly and as needed. This monitoring/evaluation results in courses of action that may include operational changes. Changes in the lift type might be from rod pump to progressing cavity pump or vice versa, from continuous to intermittent gas lift, or from rod pump to electric submersible pump (ESP) or vice versa. Equipment changes could include moving from a bottom hold down to a top holddown rod pump, from an insert to a tubing pump, or from steel to fiberglass rods. Another possible equipment change would be to add or remove a gas separator onan ESP system. Alterations in the failure-protection method might include changing from batch to continuous downhole corrosion treatment or vice versa, starting a scale-control program, changing the pump metallurgy or the ESP cable type, or running a cable with a chemical treating string. A change in the way the well is produced could be indicated, such as increasing or decreasing the stroke speed or changing the stroke length, raising or lowering the pump, anchoring the tubing, using a variable-speed drive on an ESP to reduce water production, or changing the type of power fluid in a hydraulic pumping installation. Thus, the loop is closed; the evaluation can, and sometimes does, take us back to where we started-e. g., to artificial method selection or, in some cases, to replacement/substitution. If it is to achieve its goal of maximum profitability, the process must look at each well individually. Well-by-well economics is the basis of the process. Artificial-Lift Selection The selection of the lift method considers the following. Geographic location. An offshore and/or Arctic location can limit the viable lift methods through size/weight restrictions or environmental concerns. Capital cost. These include not only the lift equipment, but also the production facilities required to support the lift method (e.g., compression requirements for gas lift). Operating costs. These costs include the energy needed to operate the lift and the cost to repair lift-system failures. Production flexibility. This means evaluating the minimum and maximum rates available from the lift method based on normal operating conditions compared with expected production. Reliability. Reliability includes expected run time and is a function of the failure frequency and the logistics required to repair failures. P. 335^

Modeling and Optimization of Plunger Lift Assisted Intermittent Gas Lift Installations

ABSTRACT A novel mechanistic model for the design of plunger assisted intermittent gas lift installations is presented. The model considers the complete production cycle: accumulation of reservoir fluids in the wellbore, annulus pressure build-up, plunger/liquid slug rise, liquid production into flowline. It is based on the fundamental mass balance and conservation of momentum equations and considers all important parameters: reservoir pressure, inflow performance, tubing and flowline characteristics, plunger characteristics, available injection pressure, surface injection choke design, gas lift valve design and performance, etc. The model solution requires numerical techniques, and it is implemented as a computer program for personal computers and mainframe workstations. One of the most innovative characteristics of the model is that it incorporates, as part of the dynamic numerical simulation, experimental plunger rise data relating instantaneous plunger velocity to instantaneous liquid slippage past the plunger. As a result, liquid "fallback"losses can be estimated and need not be assumed. The model and computer program has been verified and validated both qualitatively and with field data. Comparisons of model predictions versus field data are included. To the best of the authors knowledge, this the first published work in which a full model of this type of artificial lift installation is undertaken. Finally, it is shown how the model can be used to obtain an optimum design of a new installation, considering both gas consumption costs and crude recovery. Furthermore, examples are included to show how to use the program to effectively optimize existing installations.

Recommendations and Comparisons for Selecting Artificial-Lift Methods(includes associated papers 28645 and 29092 )

Distinguished Author Series Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering. Summary Selecting the proper artificial-lift method is critical to the long-term profitability of most producing oil and gas wells. This paper compares the main selection attributes for the current eight major artificial-lift methods and provides practical guidelines, based on practical and proven technology, on the performance and operating capabilities of the methods. This paper covers beam pumping, progressing cavity pumping, electric submersible pumping, hydraulic reciprocating pumping, hydraulic jet systems, continuous gas-lift systems, intermittent gas-lift systems, and plunger lift. Introduction Correct selection of an artificial-lift method is important to the long-term profitability of most producing oil wells. Proper artificial-lift method selection also is very important for gas wells that load up with liquid and for coalbed methane wells that must be dewatered. A poor choice can reduce production and increase operating costs substantially. Once a decision has been made on the type of lift to install on a well, it rarely is reviewed to determine that the method selected was and still is the best choice for existing conditions. In addition, changing the type of lift costs money and implies that the wrong system was selected initially. Although prudent production engineering requires continuous review of the performance of the lift method to modify operating parameters or even to evaluate changing the method, once a method is chosen, it usually stays in place. A starting point in any selection process is to review current practices.Fig. 1 shows a review of about 500,000 U.S. oil wells on artificial lift. This database consists of a wide variety of conditions and a large number of operators. Various types of sucker-rod pumps are used on about 85% of the wells. Gas lift, mostly continuous flow, comes in a distant second with less than 10% usage. Electric submersible pumps (ESP's) are used only 4% of the wells. All other lift methods (hydraulic reciprocating pumps, progressing cavity pumps, and plunger lift) represent less than 5% total usage. Remember that about 400,000 of these wells are classified as stripper wells that produce <10 BOPD. When the stripper wells are excluded, the 100,000 orso remaining U.S. oil wells are relatively high-rate artificially lifted wells. Most of these wells (53%) are gas lifted. About 27% are on rod pumping, 10% are on ESP's, and <10% are on hydraulic pumps and jets. All other methods total less than 1%. By far, the majority of offshore gas-lift wells are on continuous gas lift. Proper selection of the best lift method usually is based on strong opinions. Operating personnel normally select the lift method with which they are most familiar. Equipment suppliers or even in-house experts on a specific method usually recommend that their favorite method can be made to fit the requirements. This "force-fit" selection usually results in the extension of the capabilities or operating experience of the selected lift method. We typically find that improvements made solve a new problem encountered as a result of a poor original choice. Thus, we must establish the normal and, more importantly, the practical operating capabilities of the major lift methods. This paper compares eight major artificial-lift methods (Figs. 2 through7). Hydraulic reciprocating and jet pumps are combined in Fig. 5 because their surface requirements are comparable; however, they have different downhole designs, applications, and capabilities. Similarly, continuous and intermittent gas lift are combined in Fig. 6.

間欠ガスリフト井の挙動解析について

In the Kubiki oil field, oil is extracted by the intermittent gas lift system. Our concern is to reduce operating cost because of the present low price of oil. So as to optimize the intermittent gas lift system, the time taken to inject gas and the cycle frequency have been determined through trial and error and other means. If production volume can be predicted, operating cost can be reduced.The flowing bottom hole pressure curves were analyzed to calculate the productivity index, reservoir pressure and fall back volume. Our prediction is based on these three statistics.We used this method of statistical analysis to predict the amount of oil that was extracted from one of our wells and the prediction closely corresponded with the actual production data. Therefore our statistical method seems to be successful.

Optimal and heuristic scheduling for intermittent gas lift operations

The purpose of this paper is to study the scheduling problem in the intermittent gas lift operations, and to present a mixed integer programming (MIP) formulation for solving it. Some heuristic methods are also developed to gain insight into the gas lift scheduling problem of larger problem size. Finally, the performances of the heuristic methods are compared and contrasted based on the computational efficiency and the solution quality.

Microprocessors Play a Major Role in Optimizing the Intermittent Gas Lift System in the Ventura Avenue Field

Summary Microprocessor-assisted programmable controllers have been installed as time-cycle control devices in Getty Oil Co.'s intermittent gas lift operation in the Ventura Avenue field. Electric clock intermitters located at each well site were replaced by centralized programmable controllers. intermittent gas lift cycles for 125 wells are now controlled by nine programmable controllers that use microprocessors as the timekeeping mechanism. With accurate control by the programmable controllers and the use of a specially designed computer program. individual well gas lift cycles are scheduled so that the demand for compressed gas at the compressor station is constant. A constant demand for compressed gas has eliminated compressor discharge rate and pressure fluctuations, therefore providing more efficient gas lift operations. In addition to accurate control of gas lift cycle timing, the centralized programmable controllers offer a much faster method of changing cycle length and cycle frequency. It is now more feasible to experiment with combinations of cycle length and frequency for each well to achieve the optimum gas-liquid ratio (GLR). As a result of more efficient well operations, the total system efficiency has improved, and compressor fuel gas requirements have dropped significantly. Introduction The Ventura Avenue field is located in southern California approximately two miles north of the city of Ventura in Ventura County (Fig. 1). Getty Oil Co. operates that portion of the field located at the east of the riverbottom area portion of the field located at the east of the riverbottom area of the Ventura River. The Ventura Avenue field produces from two major zones or "blocks"-C Block and D Block. Wells completed in C Block produce from depths between 5,000 and 8,000 ft [ 1.5 and 2.4 km]. D Block wells produce from 8,000 to 13,000 ft [2.4 to 4.0 km). The development of the D Block zones began in 193 1. Early development was rather slow owing to deep drilling problems, but active development continued into the early 1960's. Wells usually came in flowing at 200 to 900 BFPD [32 to 143 m3/d fluid] and continued to flow for 7 to 10 years. It was for these D Block wells that the current gas lift system originally was developed. Not only was there plenty of produced gas to be processed as fuel for the gas-fired compressor engines, but there was also plenty to be used in the compressors as recycle gas. The plenty to be used in the compressors as recycle gas. The wells were produced originally on continuous lift. but as production rates declined, intermittent lift proved to be production rates declined, intermittent lift proved to be more economic. D Block currently produces approximately 9,000 BFPD [ 1431 M3 /d fluid], 5,800 BFPD [922 m 3/d fluid] by rod pump and 3.200 BFPD [509 M3 /d fluid] by intermittent gas lift. Waterflood operations recently were initiated in D Block, although approximately 72 % of the current D Block production is still considered primary production. Many waterfloods ultimately will be primary production. Many waterfloods ultimately will be required to develop D Block because of numerous fault blocks and massive zone thickness (greater than 1,000 ft [300 m] in some wells) of D Block. The first D Block waterflood was initiated in Jan. 1980. injection into the second and third waterfloods began in Jan. 1983 and Dec. 1983, respectively. Eleven more potential D Block waterflood projects have been identified potential D Block waterflood projects have been identified for future consideration. A major impact of the waterflooding operations is the expected increase in fluid production and the corresponding decrease in gas production. An analysis was made to estimate the remaining effective life of the gas lift system operation in conjunction with the waterflooding operation. The analysis projected that the fuel gas and recycle gas required to lift the expected fluid volumes will be greater than the produced gas volumes within the next five years. Intermittent gas lift can be less expensive than rod pumping, especially at depths associated with D Block. pumping, especially at depths associated with D Block. For this reason, an investigation was conducted into ways to improve the efficiency of the current gas lift system operation, thus extending the remaining life of the system. The recommendations from the investigation were as follows.Conduct a diligent search for gas line leaks and repair immediately.optimize single-well GLR'S. Recycle gas requirements will be minimized, thus reducing fuel gas usage.Minimize compressor discharge pressure and rate fluctuations. A balanced system must be achieved for maximum system efficiency. On the basis of these recommendations, a search for gas line leaks was carried out. All lines were pressure tested and leaks repaired. Because of the age of the gas JPT P. 696

Hydrodynamic Model For Intermittent Gas Lifting of Viscous Oil

Abstract A hydrodynamic model was developed for intermittent gas lift. Simulation results were verified by experimental tests conducted with a 60 ft high 3 in. diameter test facility using air and an oil with viscosity of 108 cp. The simulation program was also successfully applied to data gathered on an instrumented intermittent gas lift well. Results of the study indicate that initially the liquid slug undergoes a rapid acceleration and then accelerates at a much lower rate until the surface is reached, at which time rapid slug acceleration again occurs. It was found in this study that a significant portion of the liquid produced at the surface sometimes more than 50 percent, was contributed during the afterflow (i.e. liquid recovered in the form of entrained liquid in the gas core). In addition, the study has shown that by increasing the injection pressure, a higher recovery can be achieved more rapidly, but only at the pressure, a higher recovery can be achieved more rapidly, but only at the expense of increased gas injection. The model is also capable of predicting the cuing to tubing pressure ratio at which a minimum GOR will predicting the cuing to tubing pressure ratio at which a minimum GOR will occur. This minimum GOR pressure ratio was found to be sensitive to fluid viscosity.

A Field Test and Analytical Study of Intermittent Gas Lift

Abstract A series of controlled experiments of intermittent gas life were carried out in an instrumented well in the Conroe field, Montgomery County, Tex. The well was equipped with seven pressure transducers over the length of the tubing string so that progress of the lifted slug of liquid could be followed up the tubing. Unique to the experimental setup was a surface-controlled, bottom-hole hydraulic valve that allowed for letting a liquid load into the tubing, closing the valve, and isolating the well from the controlled test. Thus, individual intermittent slugs could be studied independent of the well performance. A wide range of slug sizes and injection gas volumes was covered in the 52 test runs.Understanding the action of the gas-life valve is quite important in predicting intermittent-gas-lift performance. Gas-Lift valve action depends somewhat performance. Gas-Lift valve action depends somewhat on the pressure and forces acting upon the stem of the valve. Gas-life literature has assumed that this pressure is equal to the pressure in the casing once pressure is equal to the pressure in the casing once the valve opens. Tests carried out as a result of valve action seen in the instrumented well clearly indicate that this assumption is not valid. Some pressure between the casing pressure and the tubing pressure between the casing pressure and the tubing pressure will exist on the valve stem when the valve pressure will exist on the valve stem when the valve is open; and it is extremely important to be aware of this in predicting valve action. Some design techniques predict the amount of solid liquid slug that will be predict the amount of solid liquid slug that will be brought to the surface and assume that any additional liquid produced in the afterflow of gas will be negligible. It was observed in these tests that a significant portion of the liquid produced at the surface sometimes as much as 50 percent was contributed by this afterflow there will be a considerable discrepancy between predicted and actual results.Liquid recovery from individual runs did not correlate directly with any of the measured parameters. However, it appears that the amount of the liquid slug that is not produced can be correlated with the average gas velocity produced can be correlated with the average gas velocity below the slug. Since the starting slug size is known, the correlation can be used as a predictive technique in intermittent-gas-lift design. The design method has been compared with a field test. Introduction Although intermittent gas lift has been used for artificial lift in oil wells for many years, little concrete technology has been developed for it. Design methods and behavior predictions are as much an art as a science. There have predictions are as much an art as a science. There have been two major attempts to remedy the situation. White et al. attempted to analyze the motion of a finite slug of liquid propelled to the surface by gas injected at high pressure underneath. Supporting their premise by a modicum pressure underneath. Supporting their premise by a modicum of experimentation, they published results in the form of design curves. Brown and Jessen, on the other hand, attempted no analytical solution, but did extensive field testing to develop an empirical foundation for intermittent-gas-lift technology. Unfortunately, there was considerable discrepancy in the results of the two studies.To improve the technology in intermittent gas lift, Shell Oil Co, ran a series of controlled experiments in a gas-life well in the Conroe Field, Montgomery County, Tex. The well instrumentation necessary to carry out the tests is shown in Figs. 1 and 2. (The instrumentation technology was provided by B. C. Sheffield of Shell Development Co.)To predict intermittent-lift behavior, analytical methods are needed to calculate the time rate behavior of the casing gas pressure and volume, the flow of gas through a gas-lift valve, the velocity with which a liquid slug will be raised to the surface by this gas, the amount of liquid that will be produced at the surface and the amount left behind, the pressure gradients during the process, and the time decay pressure gradients during the process, and the time decay curve for the blowdown of gas pressure after the slug has surfaced. None of these functions is independent of the others and all must be considered simultaneously in predicting lift behavior. SPEJ p. 502

Analytical and Interpretive Problems of Production Logging

Abstract Analysis of down-hole fluid movement surveys cannot be cataloged. Although there are a few so-called "cook book" methods designed to provide an easy, rapid analysis for some surveys, these should be used sparingly. When standardized interpretations are applied to fluid movement surveys with total disregard to the seemingly infinite number of variables affecting analysis, misleading results can and do occur. Cook book interpretations can cause erroneous results with the flowmeter or spinner surveys, easiest of all the down-hole fluid movement surveys to interpret. The various types of tracer and temperature surveys should never be analyzed with any sort of standardized interpretation. Some of the more common problems resulting from standardized interpretive procedures are presented in this article. Possible results of misinterpretation are presented to provide a background for more effective analysis of down-hole fluid movement surveys. Introduction Production logging, the analysis of down-hole fluid movement, generally requires more interpretation than primary logging before satisfactory results are reached. Some standard interpretation procedures have evolved in an effort to simplify the analysis of fluid movement logs. As long as these cook book procedures are recognized as being simply a basis for initiating the complete interpretation, then valid, usable results will be obtained. If a standardized form is used for the complete interpretation, the analysis of that particular production log is only partially complete, and the results may not indicate what is actually happening. Many things affect analysis of down-hole fluid movement. A few down-hole variables include hole size, laminar flow, counter or crossflow, tool efficiencies, logging speed and even, in some cases, improper running of the survey itself. Although all of these factors do not always affect the analysis of all of the various types of production logs, their effect should not be indiscriminately neglected. This article is not intended to imply that a more thorough analysis of the down-hole fluid movement survey will give the complete picture every time. However, more thorough analysis will minimize unnecessary remedial work to both injection wells and producing wells which often results from cook book methods of interpretation. Flowmeter Surveys This discussion on flowmeters is limited to the packer-type tool since analysis of the continuous flowmeter or spinner survey is generally recognized as being highly interpretive. The packer flowmeter is a very accurate tool for down-hole fluid measurement. Its major limitation is that it can measure fluid in only the pipe or borehole. The flowmeter can provide neither information about the distribution of the fluid after it leaves the borehole in injection wells nor information concerning the location of the flow channels prior to entering the borehole in producing wells. A unique problem involving profiling open-hole injection wells with a flowmeter was discussed by Jones. In this case, natural vertical fractures in the formation precluded an accurate profile by the flowmeter. Fluid flow through the spinner section of the tool created enough friction pressure to cause the fluid to bypass the flowmeter through the vertical fractures. The reduction in measured rate through the flowmeter indicated that a zone above it was taking fluid, when actually the water was reentering the borehole below the flowmeter and going on down the hole. Although the problems of obtaining accurate production profiles are less numerous and severe, one problem warrants consideration. For optimum results, flowmeter production profiles require much more down-hole information on intermittent gas-lift wells than on wells utilizing continuous gas-lift systems. The producing rate during each cycle of intermittent systems is considerably greater than the PI of the well. Consequently, an instantaneous down-hole rate obtained by a flowmeter would be totally inaccurate since the well would be pumping off. Trace A on Fig. 1 is a 15-second flowmeter recording at a point above all producing intervals, indicating a producing rate of 480 B/D. Since this is an intermittent gas-lift well and does not produce at a steady rate, a 15-second recording represents little more than an instantaneous rate. Trace B presents the flowmeter recording during the entire 6 3/4-minute lifting period. The average producing rate for Trace B is 288 B/D, but the picture is not complete until the entire gas-lift cycle is monitored by the flowmeter. Trace C presents the entire 10-minute cycle. JPT P. 993ˆ

An Analytical Description of Liquid Slug Flow In Small-Diameter Vertical Conduits

Abstract A wide range of intermittent gas-lift tests was conducted in a 1,500-ft experimental well through 1 1/4 - and 1 1/2-in. nominal size tubing. The well was equipped with two gas-lift valves, four Maihak electronic pressure transmitters and surface facilities to measure casing and tubing pressures, temperature, liquid production and the rate and volume of gas injected. For each tubing size, tests were conducted varying the slug length, gas volume injected and liquid viscosity and surface tension. From these tests, an empirical "fallback" or liquid loss correlation has been developed. No general fallback correlation could be obtained, and the correlation is presented in the form of one curve for each slug length of a given liquid and tubing size. A conceptual model has been developed which combines the fallback correlation with equations which govern liquid slow flow. A mathematical simulation of the model in the form of a digital computer program is used to calculate total recovery, gas volume used and clearance time for a given test. Tubing pressures at the gas-lift valve and at the gas-slug interface are calculated as a function of time. Tubing pressures at the surface during slug clearance are also calculated. The results compare favorably with the test data and verify the conceptual model. The extent to which the model can be used for other tubing sizes, depths, liquids and gas-lift valves can only be determined with additional experimental data. Data are also necessary so that a fallback curve can be constructed for the particular test conditions studied. Introduction The flow of liquid slugs in vertical conduits has long been an established production method in the petroleum industry. Under the name "intermittent gas lift", many advances have been made in engineering design. However, the unsteady-state nature of liquid slug flow has discouraged attempts to describe the problem analytically. The result has been that intermittent gas lift is dominated by rules-of-thumb engineering practices developed over many years. The advent of slim-hole completions has increased the demand for a more rigorous solution to the intermittent problem. Small-diameter conduits offer more frictional resistance to flow, and also reduce the slug volume lifted per intermittent cycle. Small-diameter conduits are defined to be 1 1/2-in. nominal size tubing or smaller. When oil is produced from the reservoir in which it is found, and transported to surface tanks by intermittent gas lift, three separate flow stages are encountered: flow of the fluids to the wellbore through a porous medium, vertical flow of a liquid slug from the point of gas injection to the surface, and horizontal flow of the liquid slug through the surface flowlines from the wellhead to the surface tanks. The three stages are depicted schematically in Fig. 1. The present study deals with liquid slug flow in both the vertical and horizontal conduits, ending when the bottom of the liquid slug reaches the surface. Due to the large number of variables involved, the analytical study of intermittent gas lift is extremely complex. The possibility of flow regimes other than slug type, the nature of the force fields acting on the system, the interfacial instabilities involved, the varying operational principles of existing gas-lift valves and the complete unsteady-state nature of the physical phenomena occurring in an intermittent gas-lift cycle relate some of the difficulties encountered. JPT P. 419ˆ

An Analytical Concept of the Static and Dynamic Parameters Of Intermittent Gas Lift

Abstract An analytical method for describing the events of pressure, velocity and liquid fall-back in relation to time and other well variables from initial injection to completion of an intermittent gas-lift cycle is presented herein. Development of the method proceeded from mathematical postulates verified first by the construction of an electronically instrumented model, using the principles of dynamic similarity, and later by actual field data.Application of the method to intermittent gas-lift installation design is achieved by organizing well parameters into dimensionless ratios and applying the mathematical system to describe the results of gas injection. The method permits definition of optimum values of pressure, submergence, injection rate and volume, slug velocity, depth of injection, point of cut-off, production per cycle and gas-liquid ratio for a particular well setting and set of formation characteristics. To obtain this definition, the production of a slug of fluid has been divided into three successive intervals. Three systems of differential equations, each continuous over one of the intervals, were derived and subjected to verification. The discovery of a natural constant in the gas-liquid system has resulted in major simplification of the mathematical system for design work.Correlative data are presented from past recorded installations as well as from current field tests. Introduction Examination of the geometry of an oil well during the process of delivery of a slug of fluid by gas injection reveals some interesting and important relationships. It has long been recognized that more efficient gas lift occurs when the slug arrives at the surface intact, in advance of gas bubble breakthrough. This implies that the velocity with which the liquid slug travels to the surface is sufficient to surface with solid fluid before the gas bubble penetrates all of the slug. For a proper understanding of intermittent gas lift, the relationships of pressure, volume and velocity with respect to time at various points throughout the system must be defined. For this definition, the production of a slug of fluid will be divided into three successive intervals, and three systems of equations-each continuous over one of the intervals-will be derived. Much work has previously been done in relating these variables and others in the steady-state systems of constant flow, but the unsteady-state nature of intermittent flow has made analytical solutions very difficult to obtain.One of the most important tools in present-day fluid mechanics for the analysis of complex flow systems is a dynamically similar model. Reduction of a system to a dynamically similar model enables research to fill the gap between the theoretical calculation and the predicted results. An important item of experimental data in this paper is the evaluation of the velocity with which a gas bubble penetrates liquid above in vertical conduits. It has been necessary both to evaluate vb for various systems and to correlate it to other gas-lift dimensionless ratios. Two basic assumptions were made and verified by experimentation:the slug velocity v, reaches an essentially constant value very rapidly; andthe velocity at which the top of the gas bubble penetrates the liquid above is constant. THEORY AND DEFINITIONS Fig. 1 represents a very basic schematic drawing of an intermittent gas-lift well before, during and after an injection cycle. JPT P. 301^

Evaluation of Valve Port Size, Surface Chokes and Fluid Fall-Back in Intermittent Gas-Lift Installations

Abstract By utilizing an 8,000-ft experimental field well equipped with 10 gaslift valves and 10 Maihak pressure recorders, gas-lift tests were conducted with port sizes ranging from 5/16 through 1 in. The well was equipped to provide accurate means of measuring surface pressures, temperatures, quantity of injection gas and fluid production. The tests were conducted in 2 3/8-in. OD tubing, and the well was making 95 per cent water. A complete evaluation of gas-lift-valve port sizes shows the relationship of per cent recovery, gas-liquid ratios, minimum pressure created at the operating valve and horsepower requirements for each port. The length of time necessary for the fluid in the tubing to reach equilibrium conditions after each cycle was recorded. Fall-back of fluid at depths of 477, 969, 1,685, 2,493 and 4,290 ft was noted. For each port size, pressure loads of 250, 300, 350, 400 and 450 psi were lifted with a valve operating at approximately 550 psi at 6,000 ft. Gas-liquid ratios for each load were varied from excess gas to a gas volume per cycle whereby the load failed to reach the surface. Numerous curves are presented in evaluating the accumulated data. The results show a 1-in. port to be the most efficient under all conditions. The production of intermittent liquid slugs against different-sized surface chokes was evaluated. These tests were conducted from a 7/16-in. ported valve at 4,072 ft. Tests indicate that, when possible, a 3/4-in. in diameter choke or larger should be used at the surface. Introduction In the past few years most of the advancement in gas-lift operations has been made in continuous-flow operations. Yet, it is estimated that at least 70 per cent of the wells on gas lift in the United States are of the intermittent type. Since the term "slug flow" is sometimes used in both intermittent- and continuous-flow operations, it would be well to distinguish between the two types of flow. Continuous-flow gas lift is defined as a method whereby the fluids are produced at a continuous rate at the surface. This generally requires a continuous injection of gas through a surface choke; however, various other control devices sometimes are installed to eliminate freezing, to shut-off gas during natural flow periods, etc. The actual flow of fluids in the tubing may be of the slug type (one of many flow patterns known to exist in continuous flow). Intermittent flow is defined as a method of gas lift whereby the liquid is produced in separate piston-type slugs. Perhaps this type of flow could best be thought of as a ballistic type flow where the liquid leaves bottom as a piston, propelled by a slug of expanding gas. Gas generally is injected through some type of control at the surface at predetermined intervals. However, the valve may have characteristics whereby gas can be injected through a small choke and still result in a ballistic-type flow. The purpose of the experimental work was to evaluate the most efficient port size to be used on the operating valve for the ballistic type of lift and, in addition, to establish the importance of utilizing a surface choke large enough to allow slugs to be produced without detrimental effects. This work is part of a comprehensive study of both intermittent and continuous-flow gas lift, representing a joint project conducted by the Ohio Oil Co., the Sun Oil Co., Otis Engineering Corp. and The U. of Texas. The problem of evaluating port sizes has been given little previous attention. Some work undoubtedly has been done which has not been published to date. Some tests were conducted when the wireline, mechanically-opened valve (Nixon) first came on the market. This valve was capable of utilizing full tubing area as its port size. It is known that this was a very efficient valve, but to the authors' knowledge the results of tests have never been published. EXPERIMENTAL EQUIPMENT These tests were conducted on an actual field well, the Ohio-Sun Unit Well No. 2-E, in the North Markham- North Bay City field, Matagorda County, Tex. The well incorporated 2 3/8-in. OD tubing and produced 95 per cent water. Since the running of equipment was to be quite elaborate and expensive, a well was selected in which both intermittent- and continuous- flow tests could be conducted. This particular well was capable of producing in excess of 1,000 B/D of liquid (95 per cent salt water), yet with a 3/64-in. in diameter bottom-hole choke, production was controlled to 82 B/D. Most of the intermittent tests were conducted at this low rate. Figs. 1 and 2 show all the surface and downhole equipment. As can be seen, every attempt was made to insure that ample equipment was available for reliable testing procedures. Fig. 1 shows the surface testing equipment. JPT P. 315^

Performance of an Alternate Repressuring and Producing Project

Introduction A reservoir which is being subjected to an alternate repressuring and producing mechanism is the Rincon field Frio D–7 sand lens located 16 miles northeast of Rio Grande City, Starr County, Tex., along the Vicksburg flexure and the southwestern edge of the Rio Grande embayment. As in most Frio fields in this area, numerous sand lenses are encountered and, in this instance, throughout 12 distinct strata. The subject reservoir, the D–7, was the seventh reservoir to be outlined in the D stratum. The D–7 reservoir shown in Fig. 1 is a 38 acre-ft, sand lens located at a subsea depth of - 3,230 ft on the west side of the Rincon structure. Only two wells, T. B. Slick HB No. 90 and 91, were drilled into the sand lens, encountering 12 and 16 ft of sand, respectively. Although Well No. 91 was cored, no analysis was obtained; therefore, 23 per cent porosity and an irreducible water saturation of 24 per cent, the average figures in Frio D sands in this area, were used. A fluid analysis is not available from the D–7 reservoir. Therefore, an analysis from the D–5 reservoir (sand) in proximity to the subject reservoir was used to obtain the assumed formation volume factor of 1.172 at 1,523 psi and 155°F. Primary Performance History In June, 1941, the T. B. Slick HB No. 91, the only well that produced during primary operations, was completed in the D–7 reservoir and potentialed for 166 B/D, no water, flowing through a 1 1/64 in. choke with a GOR of 311 cu ft/bbl, and tubing pressure of 320 psi. Flow valves were installed in Aug., 1944; in Feb., 1946, the well was shut in due to low productivity. The flow valves were repaired in Dec., 1947, and the well was re-potentialed for 45 B/D. The well then produced until Feb. 21, 1950, at which time it was permanently shut in due to low productivity. The primary production history of the reservoir is illustrated in Fig. 2. Cumulative production at the end of the primary life was 80,820 bbl of oil, no water and 159,872 Mcf of gas. Bottom-hole pressures taken in 1948, 1950 and 1951 are thought to be in error and probably represent gas-lift system pressures caused by a leaking valve. The gas-oil ratio increased from 311 to 52,800 cu ft/bbl, but the accuracy of the erratic gas-oil ratio history after 1946 is questionable and can probably be contributed to the inherent industry-wide problem of measuring injection gas during intermittent gas-lift operations.

Theoretical and Practical Aspects of Free Piston Operation

Abstract Theory of operation of the free piston as well as practical limits of the device in prolonged flowing life of wells producing from volumetric type reservoirs are discussed. Reservoir behavior and the gas expansion work formulae are used to exhibit utility of free piston in prolonging natural flowing life. Examples are exhibited to show actual performance of the tool in West Texas. Investment and operating costs of the free piston are compared with those required for other artificial lift methods. A nomograph which may be used in determining adaptability of the tool is exhibited. Use of the free piston in intermittent gas lift operations is briefly mentioned. Introduction The basic idea of interposing in the tubing of a producing well of a solid interface, between gas and liquid phases of the produced fluid, to increase the efficiency of the lift is not new. In the original plunger lift the interface used was a solid critical diameter piston. The increase of efficiency of lift was obtained by better utilization of the energy of the compressed gas, either of the formation gas or of compressed gas supplied to the well from an outside source. Reduction to a minimum of the channeling of gas through the liquid phase and the filling back of the oil and water to be produced resulted in better utilization of the energy. This type of installation required a perfectly cylindrical and uniform diameter tubing to permit the travel of the tool. Several years ago a free piston was developed which incorporated an expanding rubber element for sealing against the tubing wall and was therefore applicable in any conventional tubing string. Fig. 1 shows the piston. The piston is manufactured in two types: Type 1, which is designed for installations using an outside source of gas; and Type 2, which is designed for those installations which use the well's own energy as a driving mechanism. This paper will consider only the latter type of free piston which has had considerable success in operations in West Texas, with the performance of the Type 1 only very briefly mentioned later in the text.