Gas Lift Wells Research Articles

High-Pressure Gas Lift for Deep, Sour Production

Summary An innovative high-pressure N2 gas-lift design has been used to return several wells to production in the Jay/Little Escambia Creek (LEC) field of northwest Florida. The N2 was available from a field tertiary injection project and provided the means for the first continuous N2 lift system, and some of the deepest gas-lifted wells in operation. The design accommodates the unique demands of gas-lifting a deep, sour oil well with high water cuts through the operation of a continuous N2 lift system. Because the project design was not limited to conventional artificial lift techniques, a solution was achieved with the resources available. The high-pressure N2 lift enabled wells to return to production that would not have been economically attractive or mechanically feasible with a standard hydrocarbon gas lift or submersible pump design.

GAS LIFT IN BASS STRAIT

Gas lift has proved a most effective artificial lift method for the fields operated by Esso Australia Ltd in Bass Strait for the Esso-BHP joint venture. Gas lift is now used to produce approximately 5 st ML/d of the total crude production from the Strait. It has enabled wells to be produced to water cuts higher than 90 per cent, increasing the oil recovery from the fields by up to 35 per cent.Gas lift work in Bass Strait to date has included the use of special packoff gas lift assemblies for wells with sliding sleeves, the development of a tool to assist the opening of the sleeves, improved operating techniques to limit slugging from gas-lifted wells, and the testing of gas lift performance. Gas lifting has been more successful than expected, and as a result, workovers initially planned to install full gas lift strings for older wells have not been necessary. The two phase flow correlations available have been improved to match the performance of the gas-lifted wells. The correlations are now used to design tubing strings with a number of gas lift mandrels prior to running the initial completions and to select the optimum gas injection depth.Future work in gas lift for Bass Strait will involve the optimisation and automation of lift gas distribution on the platforms. Gas lift will also be used for planned future developments, including mini-platforms and subsea completions.

Pressure Buildup in Gas-Lift Oil Wells, Falah Field, Offshore Dubai

Summary Extensive pressure buildup testing was carried out in the gas-lift wells of the Falah field offshore Dubai. These tests were to gather reservoir information for use in a three-dimensional (3D) reservoir simulation model. Pressure testing was carried out with conventional Amerada bombs, downhole memory recorders, and continuous monitoring by means of an electric line unit with a Geophysical Research Co. (GRC) gauge. We also attempted to use a downhole shut-in tool with surface pressure readout. pressure readout. Log-log plots of pressure change vs. time displayed two different periods of wellbore storage in some wells as a result of a mechanism that occurred following shut-in. This type of behavior has not been reported in the literature and leads to a very complicated interpretation of the test data. The data were analyzed by type-curve matching techniques to identify the interpretation model. Radial flow was observed in only two wells. Other wells showed dominance of wellbore storage in spite of long shut-in periods-as long as 3 weeks. This was caused in part by expansion of annulus gas into the tubing part by expansion of annulus gas into the tubing immediately after shut-in. The gas expansion caused wellbore fluids to be injected in the reservoir and appeared as the first period of wellbore storage. The second period of wellbore storage occurred when the flow was period of wellbore storage occurred when the flow was reversed. This mechanism was modeled analytically by writing the superposition equation for a single well with wellbore storage and skin. Recognizing this mechanism, we designed a special test with reduced production rate that proved successful in providing interpretable data. This paper presents the results of buildup testing in three wells. The buildup shapes show marked differences caused by changes in wellbore conditions. Recognizing this type of buildup behavior is very useful indesigning the tests,cautioning against data that may appear as a straight line to Homer plot, andshowing inadequacy of short-term buildups to gather pressure data for history matching purposes in field-scale pressure data for history matching purposes in field-scale simulation models. Introduction A pressure buildup survey program was undertaken in the gas-lift oil wells of Falah field to supply data for a detailed simulation study. An electric line unit with GRC gauge was used to record the buildup in Well FA-5 for about 3 weeks. One week after the survey had started, the remaining wells were shut in conjunction with scheduled maintenance for the gas-lift compressor. Before the wells were shut in, downhole memory recorders were lowered in four additional wells, which were shut in for 7 to 10 days. Data from all Falah wells except Well FA-6 showed a slope that increased after the generally expected period of wellbore storage when a log-log plot of deltap vs. deltat was prepared. This increase in four out of five wells surveyed prepared. This increase in four out of five wells surveyed showed that wellbore storage was a real phenomenon rather than malfunctions in the pressure recording equipment. With the exception of Well FA-5, the subject wells had been surveyed upon initial completion and showed perfectly normal buildups. Thus, the recent buildup perfectly normal buildups. Thus, the recent buildup shapes were caused by reservoir pressure decline resulting from depletion and current wellbore pressures. It is theorized that as a result of low flowing bottomhole pressures (BHFP's), gas from the casing pushes the pressures (BHFP's), gas from the casing pushes the liquid into the formation upon shut-in, which results in two different periods of wellbore storage. Previous authors have hinted at this type of mechanism but did not show data to demonstrate it. Well FA-5 provides an excellent example of it. To overcome the flow-reversal mechanism, we decided to repeat the buildup survey in Well FA-5 with a downhole shut-in tool. Unfortunately, this approach had to be abandoned because of mechanical failures. We then decided to select another well, FA-4, and to stabilize it at a reduced rate in an effort to raise the BHFP and to reduce, if not eliminate, the reversal of flow after shut-in. The data obtained in this manner, although still dominated by wellbore storage, provided interpretable results. Three examples of buildup tests are included in this paper. paper. The first example discusses Well FA-5 data and demonstrates the flow-reversal mechanism, which was analyzed as such and as a changing-wellbore-storage phenomenon by type-curve matching. phenomenon by type-curve matching. The second example illustrates tests on Well FA-4 upon initial completion (Oct. 1978), Nov. 23, 1981, and Dec. 23, 1981. The third test on this well was done after the well was stabilized at a reduced flow rate. The third example includes data from Well FA-6, which showed normal buildup in Aug. 1979 and during the July 1981 survey. JPT P. 466

Economic Approach to Oil Production and Gas Allocation in Continuous Gas Lift (includes associated papers 10858 and 10865 )

Summary Allocation of gas to wells on continuous lift can affect profitability. Excessive gas input is costly because of high gas prices and compressing costs. Inefficient gas allocation in a field with limited gas availability also reduces profitability. To alleviate the problem of excessive gas usage, an economic slope that relates liquid production and gas injection to cost and profit has been developed. To resolve the problem of gas allocation in a field with limited gas, a method to allocate gas to wells efficiently under this situation is presented and a step by step procedure is given. An example problem consisting of a six-well field is solved to illustrate the procedures presented. Introduction The current energy situation and the increasing costs of gas lift are forcing oil operators to consider economic operations first rather than desired maximum production. As the market price of oil continues to increase, it is understandable that oil operators would prefer gas lift wells to produce at a maximum. In fact, optimization in continuous gas lift has come to mean the injection of gas until maximum production is achieved. On the other hand, gas prices and compression costs continue to increase, forcing the oil operator to approach maximum production cautiously. In view of this situation, the development of a procedure to determine the optimal economic point to produce a well or a group of wells was recognized as having a high potential for gas-lift design improvement. The economic slope concept offers a good approach to the problem. This slope relates the well and reservoir parameters to cost and profit. The performance of a well on continuous gas lift can be described by a typical gas requirement plot (liquid flow rate vs. gas injection) as shown in Fig. 1. Any point of tangency to the curve is unique and describes a certain situation. For instance, the point of tangency that occurs at 0 deg. slope indicates the gas injection that will yield maximum production. If this slope coincides with the economic slope, the determination of the economic optimum is clear-cut since only one maximum exist. However, the economic slope usually occurs at a slope greater than 0 deg., so obtaining the optimal economic point can become tedious. In fact, efforts made in the past yielded procedures that are very cumbersome. This paper, therefore, presents (1) the formulation of a simple slope, (2) the use of this economic slope in a simple procedure to allocate gas, at the optimal economic point, to a well or a group of wells(given an unlimited gas situation), and (3) the determination of total gas required for a field, thus simplifying compressor sizing. Another important aspect of gas allocation that deserves attention is the area of limited gas. A method is presented that uses a simple graphical procedure to allocate gas to wells efficiently in a field operating under such a condition. A six-well field is used to illustrate the procedures presented. Economic Formulation The gas requirement plot (Fig. 1) is indispensable in any useful analysis of gas allocation in continuous gas lift because it relates liquid production to gas injection. This liquid production/gas injection relationship is the cornerstone of any economic approach. To obtain an economic slope, it is necessary to formulate mathematically a function of gas injection and liquid production on one hand and cost and profit on the other. JPT P. 1887^

Corrosion Control of Gas-Lift Well Tubulars By Continuous Inhibitor Injection Into the Gas-Left Gas Stream

Two treating systems have been developed to provide corrosion control of gas-lift well tubulars by continuously injecting corrosion inhibitor into the gas-lift gas stream. The amount of inhibitor injected is controlled by either a system of proportional divider valves or by an auto mated time-shared proportional divider valves or by an auto mated time-shared system using an electronic scanner and an adjustable time to control solenoid valves. Introduction Internal corrosion of tubulars in gas-lifted oil wells along the Texas Gulf Coast is widespread and often quite severe. The corrosion attack is caused by production of large volumes of salt water, particularly from the predominantly water drive reservoirs in this area, predominantly water drive reservoirs in this area, coupled with the presence of carbon dioxide in the produced gas. Carbon dioxide dioxide dissolved in salt produced gas. Carbon dioxide dioxide dissolved in salt water forms an acidic brine solution that causes a general corrosion attack on steel tubulars. This form of corrosion often results in heavy localized pitting, with the greatest metal loss in gas-lifted wells usually occurring in the portion of the tubing string above the operating gas-lift portion of the tubing string above the operating gas-lift valve. Corrosion severity is often such that tubing strings require replacement as frequently as every 6 months. Plastic-coated tubing has solved, to an extent some of our severest tubing corrosion problems; but it cannot be economically justified in many instances. During the past several years, corrosion has become an increasing problem as a result of the need for capacity production. Corrosive high-water-cut wells are being production. Corrosive high-water-cut wells are being produced; and additional turbulence in the tubing from produced; and additional turbulence in the tubing from higher producing rates accelerates the corrosion-erosion attack. This paper describes systems developed to replace conventional down-hole corrosion-inhibitor batch treatments with continuous inhibitor injection into the gas-lift stream. The systems allow control of treatment for individual wells. Conventional Corrosion Control Methods Corrosion of steel tubulars in gas-lift wells can be controlled by application of properly selected corrosion inhibitors. Corrosion control programs for gas-lift wells commonly use one of the following batch treating techniques: Tubing displacement Corrosion inhibitor in displaced to the bottom of the tubing string with the inhibitor forming a protective film on the tubing. Weighted inhibitor weighted corrosive inhibitor is pumped into a well where it falls to bottom then slowly comes back in the produced fluid, forming and replenishing a protective film on the tubing. Formation squeeze Inhibitor is squeezed (pumped) into the producing formation; inhibitor is adsorbed on the formation and subsequently desorbs into the produced fluids, forming and replenishing a protective film on the tubing. Successful corrosion control programs using these treating methods are expensive, since they usually require a truck-mounted pump and operator in addition to the inhibitor. Schedules for such programs are frequently difficult to maintain, resulting in treatment inconsistency. It is also difficult to optimize treatment size vs frequency to avoid periods of under-or over-treatment. Operating problems often associated with programs using batch treating techniques are the following (1) Wells must be shut in to treat, resulting in lost production. JPT p. 624

Two-Rate Flow Test, Variable-Rate CaseApplication to Gas-Lift and Pumping Wells

A disadvantage of the familiar two-rate flow test is that the flow rate during the two flow periods must be constant. Here is an extension of the method that can handle variable rate in the second flow period. The test is particularly well suited to wells that have been producing at stable rates for a relatively long time. Gas-lift or pumping wells usually qualify as prime candidates for this approach. Introduction Pressure buildup analyses are widely used to obtain Pressure buildup analyses are widely used to obtain reservoir data such as effective flow capacity of the formation. However, over the years several drawbacks, arising from the procedure of shutting in the well at the wellhead, have become apparent. The mathematics of pressure buildup analysis is based on the assumption that the well is shut in at the sand face, and that no production occurs after the well is shut in. In practice, the well is closed at the surface, and flow into the wellbore continues for a period of time. This is referred to as afterflow. Afterflow in some cases, especially in tight reservoirs, can last for many hours. This requires that the well be shut in for a long period so that data may be obtained that are free of afterflow. When the shut-in period is long, the loss in production may make it period is long, the loss in production may make it uneconomical to conduct a pressure buildup test. Drawdowns are free of afterflow. However, they suffer from two drawbacks. The first is the requirement that pressure be completely stabilized before the test is run. This means a full buildup must precede a drawdown. The second drawback is that the precede a drawdown. The second drawback is that the annulus unloads during the test, and this complicates the analysis. In 1963 Russell published the two-rate flow test, which is designed to eliminate the disadvantages of buildups and drawdowns. The two-rate flow test conducted on a flowing well does not require a shut-in period. Thus it is free of afterflow, and no loss in period. Thus it is free of afterflow, and no loss in production is incurred. The disadvantage of the production is incurred. The disadvantage of the two-rate flow test is that the flow rate during the second flow period must be constant. This is hard to achieve, and a small drift in the rate, if not accounted for, may lead to considerable error in the calculated results. This is so because a small drift in rate affects the slope of the straight line of the pressure vs log time function plot, and the results are very sensitive to the value of the slope, as reported by Selim. To eliminate some of the difficulties encountered in the two-rate test analysis, Selim proposed a modification that consisted of following the rate reduction (second rate) with a rate increase. The modification still requires constant-rate flow and results in lengthening the test time. In this paper we eliminate the disadvantages of the two-rate flow test and maintain its advantages by removing the constant-rate requirement during the second flow period. Thus the test is easier to run, and any fluctuation in rate is accounted for in the calculations. The two-rate flow test, variable-rate case, is suited to wells that have been flowing at stable rates for a period that is relatively long compared with the second period that is relatively long compared with the second flow period. It is also suitable when semisteady-state flow occurs during the first flow period. Pumping and gas-lift wells usually meet this requirement and are prime candidates for the test. In particular, the prime candidates for the test. In particular, the afterflow periods of buildup on these wells are readily analyzed with this approach. JPT P. 93

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

Predicting Two-Phase Pressure Drops in Vertical Pipe

Abstract A method is presented which can accurately predict, with a precision of about 10 percent, two-phase pressure drops in flowing and gas-lift production wells over a wide range of well conditions. The method is an extension of the work done by Griffith and Wallis and was found to be superior to five other published methods. The precision of the method was verified when its predicted values were compared against 148 measured pressure drops. The unique features of this method over most others are that liquid holdup is derived from observed physical phenomena, the pressure gradient is related tot eh geometrical distribution of the liquid and gas phase (flow regimes), and the method provides a good analogy of what happens inside the pipe. It takes less than a second to obtain a prediction on the IBM 7044 computer. Introduction The problem of accurately predicting pressure drops in flowing or gas-lift wells has given rise to many specialized solutions for limited conditions, but not to any generally accepted one for broad conditions. The reason for these many solutions is that the two-phase flow is complex and difficult to analyze even for the limited conditions studied. Under some conditions. the gas moves at a much higher velocity than the liquid. As a result, the down-hole flowing density of the gas-liquid mixture is greater than the corresponding density, corrected for down-hole temperature and pressure, that would be calculated from the produced gas-liquid ratio. Also, the liquid's velocity along the pipe wall can vary appreciably over a short distance and result in a variable friction loss. Under other conditions, the liquid is almost completely entrained in the gas and has very little effect on the wall friction loss. The difference in velocity and the geometry of the two phases strongly influence pressure drop. These factors provide the basis for categorizing two-phase flow. The generally accepted categories (flow regimes) of two-phase flow are bubble, slug, (slug-annular) transition and annular-mist. They are ideally depicted in Fig. 1 and briefly described as follows. BUBBLE FLOW (FIG. 1A) The pipe is almost completely, filled with the liquid and the free-gas phase is small. The gas is present as small bubbles, randomly distributed, whose diameters also very randomly. The bubbles move at different velocities depending upon their respective diameters. The liquid moves up the pipe at a fairly uniform velocity and, except for its density, the gas phase has little effect on the pressure gradient. SLUG FLOW (FIG. 1B) In this regime, the gas phase is more pronounced. Although the liquid phase is still continuous, the gas bubbles coalesce and form stable bubbles of approximately the same size and shape which are nearly the diameter of the pipe. They are separated by slugs of liquid. The bubble velocity is greater than that of the liquid and can be predicted in relation to the velocity of the liquid slug. There is a film of liquid around the gas bubble. The liquid velocity is not constant whereas the liquid slug always moves upward (in the direction of bulk flow); the liquid in the film may move upward but possibly at a lower velocity, or it may move downward. These varying liquid velocities will result not only in varying wall friction losses, but also in a "liquid holdup" which will influence flowing density. At higher flow velocities, liquid can even be entrained in the gas bubbles. Both the gas and liquid phases have significant effects on the pressure gradient. TRANSITION FLOW (FIG. 1C) The change from a continuous liquid phase to a continuous gas phase occurs in this region. The liquid slug between the bubbles virtually disappears, and a significant amount of liquid becomes entrained in the gas phase. JPT P. 829ˆ

Practical Use of Recent Research in Multiphase Vertical and Horizontal Flow

ABSTRACT A recent correlation for multiphase vertical flow by Hagedorn and Brown1has been used to examine the effect of numerous variables such as pipe size, gas-liquid ratio, liquid flow rate, liquid viscosity, liquid surface tension, oil API gravity, water cut, etc., on flowing pressure gradients. Most previous correlations were derived by using a form of the generalenergy equation which assumed negligible changes in kinetic energy. Undercertain flow conditions this can lead to serious errors in predicting pressuretraverses. Examples of traverses calculated both with and without the kineticenergy term are included here. The Chew and Connally correlation for calculating change, in viscositywith changing pressure and temperature has been extended so that the effect ofa changing viscosity with depth on pressure gradients can also bepredicted. Examples illustrating the effect of tubing size show the importance ofthis correlation in determining pipe sizes for initial well completions. Limitations on production rates in small pipe sizes from excessive frictionlosses can be predicted with greater accuracy. The combined use of a vertical-flow correlation with a horizontal-flowcorrelation provides a method for determining the maximum flow rate possiblefrom both flowing and gas-lift wells. Examples are included to illustrate application of the combined use ofvertical and horizontal-flow correlations in optimizing production rates andminimizing excessive costs from over injection of gas in gas-liftwells. INTRODUCTION The problems of multiphase vertical and horizontal flow are immediatelyencountered in any producing well. Fig. 11 shows three stages ofproduction: flow in porous medium, vertical flow and horizontal flow. All threestages affect the production rate from a well. If we are confronted with a particular well and consider only the variablesinvolved in the vertical and horizontal stages of Fig. 1, we should be capableof calculating the flowing bottom-hole pressure necessary to produce aparticular flow rate. A change in any of the variables results in a newsolution to the problem. Recent approaches in developing horizontal and vertical-flow correlationshave improved to the extent that the solution can now be obtained with moreconfidence than previously.

Evaluation of Surface Back - Pressure for Continuous - And Intermittent - Flow Gas Lift

Abstract To study continuous- and intermittent-flow gas-lift wells, it is necessary to evaluate the facilities that the well fluids must pass through to reach the storage point. This paper deals with surface back-pressure and its effect on continuous-and intermittent-flow gas lift. Particular emphasis is placed on inadequate-sized flowlines for continuous flow and intermittent slugs produced against surface chokes.Numerous field tests on continuous-flow gas-lift wells show the resulting increase in production due to reducing surface wellhead pressure. A method is presented to predict and apply surface back-pressure.Controlled experimental tests show the results of producing intermittent slugs against varying surface choke sizes. A means of calculating the weighted average bottom-hole pressure is given for an intermittent cycle. This average pressure increases considerably as the surface choke size is decreased. These calculations show when a chamber installation should be considered for intermittent lift. Introduction One of the reasons gas-lift studies are made difficult is that the system concerned starts at the sand face at the bottom of the well and does not end until the storage facilities are reached. The whole system must be considered in the study because any alteration in the system, from one end to the other, will affect the drawdown at the sand face and the corresponding fluid production rate of the well. This paper deals particularly with surface back-pressure and its effect on production rates.Serious loss of production occurs when gas-lift wells are produced against excessive back-pressures at the surface. Surface back-pressure is considered to be that pressure found inside the christmas tree, just upstream from the flow-wing. This excessive back-pressure is generally caused by:high separator pressure;choke in the christmas tree or flowline;long flowline;inadequate-sized flowline;restrictions in flowline such as paraffin, scale deposits, crimped flow line, etc; anda nonstreamlined christmas tree incorporating a large number of sharp bends. Numerous field and experimental tests were conducted in actual gas-lift wells for both continuous and intermittent flow to show the effect of these restrictions. It has long been known that the production of fluids from a gas-lift well may be materially reduced by producing this fluid against a surface restriction or against high surface back-pressure. It has also been a matter of education in some instances to show why this additional back-pressure reduces the total output of produced fluids (oil, gas and water).Admittedly, there are some instances wherein a well must be treated very carefully and, in turn, excessive pressure drawdown must be avoided. This is particularly true for wells that are known to produce sand and for wells that are producing with high solution gas-oil ratios. In some wells excessive drawdown has created a gas phase around the wellbore, which in turn increases the permeability to gas and, hence, reduces the oil production.It is not the purpose of this discussion to deal with those wells in these two categories; rather, it is assumed we are dealing with wells of the type where a maximum drawdown is necessary to obtain maximum fluid production. In turn, it is desired to produce these fluids with a minimum amount of injection gas. Continuous-Flow Gas Lift Introduction It is common practice throughout the oil field to increase the fluid production rates from continuous-flow gas-lift wells by streamlining wellheads, enlarging, shortening and streamlining flowlines, and reducing separator pressures.In turn, this reduces the surface back-pressure on the well. Although this is common practice, it is known that a large percentage of continuous-flow gas-lift wells are still being excessively choked to as much as one-half of their efficient production capabilities by excessive back-pressures. JPT P. 243^

Single-and Two-Phase Fluid Flow in Small Vertical Conduits Including Annular Configurations

Abstract This paper is an analytical study of the flow of fluids through small vertical conduits. Small conduits are defined as 1 1/4-in. nominal diameter tubing size and smaller, and approximately twice this area for annular conduits (i.e., 1- × 2 1/2-in. annulus and smaller). Experimental data are presented for the 1- × 2-in. and 1 1/4- × 2 1/2-in. annuli, and the 1-in. and 1 1/4-in. tubing, since these represent the small conduit sizes and configurations generally encountered in oilfield applications. Data have been gathered for these conduits for single-phase water, single-phase gas and two-phase water-gas mixtures, with particular emphasis on high gas-liquid ratios. Water rates in excess of 2,000 B/D and gas rates in excess of 2.5 MMcf/D, and two-phase flow ratios in between these two, represent the scope of the data gathered. Existing equations have been applied to predict flowing pressures and compared with experimental data. New correlations have been developed. Introduction The increased economic pressure on the domestic oil industry in the United States has constantly required the use of new techniques and equipment designed to reduce the cost of finding and producing oil and gas. Since tangible items are most readily apparent in economic analysis, the advent of lower-cost well completions was inevitable. One of the methods used to reduce costs which has received widespread attention is the slim-hole completion technique where tubing is used as the well casing and in which small conduits are used for tubing if necessary. Small conduits, defined by Kirkpatrick as "1 1/4-in. diameter nominal tubing and smaller for tubing flow and less than twice the 1 1/4-in. diameter nominal tubing internal flow area for annulus flow", have also found widespread usage as siphon strings for dewatering gas wells and as "kill" strings in deep high-pressure oil and gas wells.The growing use of small-diameter tubing has resulted in an increased need for development of improved methods to measure or predict flowing bottom-hole pressures since the physical dimensions generally preclude the use of subsurface-recording pressure gauges. Even in the cases where small bombs are available, the relatively high velocities encountered at nominal flow rates make it necessary to use excessive weight bars or special hold-down devices.Attempts to use recognized correlations to accurately predict flowing or gas-lift performance in wells equipped with small conduits have been generally unsuccessful. Insufficient field data were available to allow the development of a correlation on this basis, and an experimental approach was applied in an attempt to obtain a workable relation. The experimental approach used to obtain the data presented in this paper was actually a compromise between a field installation and a laboratory study. A test well 1,000 ft in length was used to obtain flow data on single-phase liquid, single-phase gas and two-phase water/gas flowing mixtures. Liquid rates up to 2,200 B/D and gas rates up to 3 MMcf/D were used in the single-phase flow studies. Two-phase flow rates from 100 to 600 B/D with gas-liquid ratios from 500 to 8,000 cu ft/bbl were recorded. Experimental data were obtained for single- and two-phase flow through 1-in and 1 1/4-in. nominal tubing, and through the annuli between 1- and 2-in. and 1 1/4- and 2 1/2-in. nominal tubing strings.Experimental results for the two-phase flow are compared to the Poettmann-Carpenter correlation which is widely used as a comparative standard for development of multiphase flow predictions in flowing and gas-lift wells. Correlations developed by Tek, Baxendell and Thomas were also investigated. The experimental data recorded herein fell in between the two flow regimes as defined by Ros, and this correlation also failed to yield satisfactory results. The fact that existing correlations failed to confirm the experimental data led to the need for development of a new correlation.Although a two-phase flow study was the primary objective of this investigation, data were also recorded for single-phase flow of water and gas, and constants were developed relating to pipe roughness and equivalent diameters for annular flow. These single-phase studies assisted materially in the development of certain of the two-phase flow results.Considerable previous work has been published which presented relationship of surface measurements to bottomhole condition. The works of Buthod and Whiteley, Jones, Poettmann and the Texas Railroad Commission are classic examples of the successful use of mathematical relationships which allow acceptable predictions of subsurface pressures, when gas is the flowing fluid. Darcy and others have derived relationships which may be used with minor modifications to predict subsurface flowing conditions in injection and water-supply wells. JPT P. 309^

Laboratory and Field Tests on Titanium for Oil Field Pump and Valve Parts

Abstract Laboratory and field tests are reported for titanium parts for gas lift valves and down-hole oil well pumps. While titanium performed well in the laboratory tests using aerated fluids, and did well in field tests of gas lift wells, similar trials in wells pumping sour crude oil well showed titanium to be inferior to normally used materials. Authors conclude titanium is suitable for use in gas lift valves and could be competitive to presently used materials at a lower price. They conclude titanium is not suitable for use in oil well pumps, but might perform better if hardened. It also is at a competitive disadvantage to commonly used materials costwise. While titanium is cathodic to materials commonly used in oil wells, no marked corrosion was attributed to this property after exposure of coupon sets in a producing well. Titanium was found resistant to abrasion by sand-laden aerated oil well fluids in laboratory tests. 6.3.15, 8.4.3

The Calculation of Pressure Gradients In High-Rate Flowing Wells

Abstract Work on the calculation of vertical two-phase flow gradients by Cia. Shell de Venezuela has been based mainly on the "energy-loss" method proposed by Poettmann and Carpenter in 1952. The "energy-loss-factor" correlation proposed by Poettmann and Carpenter was based on relatively low-rate flow data. This correlation proved inapplicable to high-rate flow conditions. In an attempt to establish a satisfactory correlation for high rates, a series of experiments was carried out at rates up to 5,000 B/D in Cia. Shell de Venezuela's La Paz field in Venezuela, using tubing strings fitted with electronic surface-recording pressure elements. As a result of these experiments a correlation between energy-loss factor and mass flow rate was established which is believed to be applicable to a wide range of conduit sizes and crude types at high flow rates (e.g., above 900 B/D for 2 7/8-in. OD tubing). It is anticipated that the resulting gradient calculations will have an accuracy of the order of +/− 5 per cent. At lower flow rates the energy-loss factor cannot be considered as constant for any mass rate of flow, but varies with the free gas in place and the mixture velocity. No satisfactory correlating parameter was obtained. As a practical compromise for low flow rates, a modification of the curve proposed by Poettmann and Carpenter was used. In practice this was found to give gradient accuracies of approximately +/− 10 per cent down to flow rates as low as 300 B/D in 2 7/8-in. tubing. Introduction Production operations in Cia. Shell de Venezuela's light- and medium-crude fields are principally concerned with high-rate flowing or gas-lift wells. Under these conditions the analysis of well performance, the selection of production strings and the design of gas-lift installations are vitally dependent on an accurate knowledge of the pressure gradients involved in vertical two-phase flow. Initially, attempts were made to establish the gradients empirically as done by Gilbert, but the results were not reliable due to scarcity of data over a full range of rates and gas-oil ratios. Several methods of calculation based on energy-balance considerations were attempted, but the computations were cumbersome and the results discouraging. In 1952 a paper was published by Poettmann and Carpenter which proposed a new approach. Their method was also based on an energy-balance equation, but it was original in that no attempt was made to evaluate the various components making up the total energy losses. Instead, they proposed a form of analysis which assumed that all the significant energy losses for mutiphase flow could be correlated in a form similar to that of the Fanning equation for frictional losses in single-phase flow. They then derived an empirical relationship linking measurable field data with a factor which, when applied to the standard form of the Fanning equation, would enable the energy losses to be determined. The basic method was applied in Venezuela to the problem of annular flow gradients in the La Paz and Mara fields. This involved establishing a new energy-loss-factor correlation to cover high flow rates and, also, some adaptation of the method to permit mechanized calculation using punch-card machines. The final result was a set of gradient curves for La Paz and Mara conditions which proved to be surprisingly accurate. With the encouraging results of the annular flow calculations, several attempts were made to obtain a corresponding set of curves for tubing flow. Here, unfortunately, little progress could be made. The original correlation of Poettmann and Carpenter was based on rather limited data derived from low-rate observations in 2 3/8- and 2 7/8-in. OD tubing. It did not cover the higher range of production rates, and extrapolation proved unsuccessful. A new correlation covering high flow rates was required, but this proved to be extremely difficult to establish since tubing flow pressure measurements at high rates did not exist-due to the difficulty of running pressure bombs against high-velocity flow. The necessity for reliable tubing flow data increased with the development of the new concessions in Lake Maracaibo, where high-rate tubing flow from depths of 10,500 ft became routine. Thus, it was decided to set up a full-scale test to establish a reliable energy-loss factor for tubing flow conditions. A La Paz field light-oil producer with a potential of approximately 12,000 B/D on annular flow was chosen.

Simultaneous Flow of Gas and Liquid As Encountered in Well Tubing

Abstract The paper deals with pressure gradients occurring in flowing and gas-lift wells, a knowledge of which can be applied to the determination of optimum flow-string dimensions and to the design of gas-lift installations. The study is based on a pressure-balance equation for the pressure gradient. It appears that a pressure-gradient correlation of general validity must essentially consist of two parts-one part being a correlation for liquid hold-up and the other part being one for wall friction. Dimensional analysis indicates that both liquid hold-up and wall friction are related to nine dimensionless groups. It is shown that in the field of interest only four groups are really important. On the basis of these four groups a restricted experimental program could be selected that nevertheless covered practically all conditions encountered in oil wells. This experimental program has been carried out in a laboratory installation. Three essentially different flow regimes were found. The pressure gradients in these regions are presented in the form of a set of correlations. Comparison of these correlations with a few available oilfield data showed excellent agreement. Introduction Prediction of the pressure drop in the flow string of a well is a widely known problem in oilfield practice. Accurate data on the pressure gradient of a simultaneous flow of gas and liquid in a vertical pipe are especially useful for the determination of optimum flowstring dimensions. It is well known that with moderate gas and liquid flows such a vertical string acts as a "negative restriction". The pressure drop decreaseswhen the throughput through a given pipe increases, andwhen at a given throughput the cross-sectional area is decreased. The reason is that, with increasing velocities, the flow becomes more agitated so that the gas slips relatively more slowly through the liquid. With the resulting increase in gas content in the string, the static head decreases. When the area becomes very small, however, the high velocities entail great wall friction, which causes an increase in pressure drop. For a given flow, therefore, minimal pressure drop is obtained by using a certain cross section. This means that, in principle, each well can be provided with an optimum flow string for minimum pressure drop and, hence, maximum possible production rate. The procedure for the selection of the optimum string has been discussed by Gilbert. A necessary tool in the procedure, however, is accurate knowledge of the pressure gradient to be expected for various values of the governing variables. Another application of pressure-gradient data lies in the field of gas-lift practice: they provide a means of determining the optimum gas-injection rate, optimum injection pressure and optimum injection depth. Much work has already been done in the study of the pressure gradient of vertical gas-liquid flow. Poettmann and Carpenter presented a pressure-gradient correlation based on measurements in wells. This correlation has been found to provide accurate predictions in high-pressure wells and in high-production wells for flow through both tubing and annuli. However, when their method is checked on low pressure-low production wells or on wells with viscous crudes, serious discrepancies are found. As we shall see in the next section, this is due to the fact that their correlation factor, representing all irreversible energy losses, is given as a function of only one correlation group. Some important variables, such as gas-liquid ratio and liquid viscosity, are not incorporated in this group so that their specific effects are not accounted for. To study also the mechanism of vertical gas-liquid flow outside the ranges covered by the Poettmann-Carpenter publication and extensions, a laboratory investigation has been carried out. This study is founded on a pressure-gradient equation that is based on a pressure balance. To reduce the number of test runs required, a dimensional analysis has been carried out, followed by a selection of relevant dimensionless groups. These groups guided a subsequent experimental study, and with their aid the experimental program could be minimized while still covering the majority of the situations encountered in oilfield practice. In this paper the choice of a formula for the pressure gradient is discussed first. This is followed by a brief description of the experimental setup. Subsequently, the dimensional analysis is discussed and the relevant dimensionless groups are selected, resulting in the experimental program required.

The Evaluation of Vertical-Lift Performance in Producing Wells

Abstract The fundamentals of vertical-lift performance are examined with the aid of computer-calculated flowing gradient charts. Flowing and gas-lift well performance characteristics are determined from available well test data. The effect of tubing size, gas-liquid ratio and wellhead pressure is discussed for both flowing and gas-lift wells. The effect of gas-injection pressure, formation gas, bottom-hole pressure and valve spacing is also discussed for gas lift wells. From these studies conclusions may be reached for improving or prolonging natural flow, obtaining optimum lift efficiency when natural flow ceases and improving existing gas-lift systems. The techniques perfected satisfy the requirement that the time involved to conduct an evaluation be practical for operating personnel. Introduction Flowing pressure gradients furnish the key to successful evaluation of vertical-lift performance in producing wells. Command of multiphase flow gradients in some readily usable form is a necessity before operating personnel can competently include vertical-lift performance evaluation of both flowing and artificial-lift wells in their over-all consideration of production efficiency. A readily usable form cannot be overemphasized since most of the decisions which confront the production engineer with a problem well must be made quickly. In moving a barrel of oil from the reservoir to the stock tank, the major portion of energy generally is expended in the vertical-lift phase. This may or may not be of concern during the flowing life of a well, depending upon the production requirements. It becomes of some concern when the flow performance of the well becomes erratic, and a conscious effort must be made to maintain natural flow. It is at this time that the first steps may be taken to modify existing conditions to relieve unnecessary limitations to proper flow. When natural flow ceases and some form of artificial lift must be installed, the amount of energy expended in lifting liquids becomes quite obvious. It is at this time, if no other, that lifting efficiency becomes important because that part which must be supplied from an outside source is now related directly as a cost per barrel of oil produced.

Case Histories Show Value of Corrosion Inhibitor Squeeze Treatment

Introduction The inefficiency of batch treatment down the annulus to prevent corrosion in gas-lift wells led to a search for a better method. Squeezing inhibitor into the formation was attempted and appeared to be an improvement over other methods of treatment. With these other methods it was difficult to get the chemical where it was needed because a high fluid leg would cause a major portion of the chemical to enter the tubing string at the working valve, which was too high to give complete protection. A low fluid leg would cause the chemical to dehydrate and leave a gummy substance on the outside of the tubing and on the inside of the casing. This tendency could be partially overcome by using large amounts of diluent (5 to 10 bbl) with the chemical, but such treatment was time-consuming and expensive. Sticks and pellets were tried with poor results. Theory of Squeeze It was found that some inhibitors would adsorb to sand rapidly and would desorb slowly. Laboratory work indicated that this adsorption-desorption rate was sufficient to warrant field testing. The high chemical concentration (11,000 to 1 million ppm) in contact with the steel during the squeeze is also a factor. Limited field tests to evaluate these two factors have been performed, but are inconclusive. Squeeze Treatment Since Nov. 1954, 60 wells have been squeeze-treated with a total of 160 squeezes. These 60 wells are located in 10 different fields and produce from 19 separate reservoirs. They vary in depth from 3,000 to 12,000 ft. Of the 60 wells, four are natural flowing wells, 47 are gas-lift wells, eight are gas condensate wells, and one is a pumping well. From the information available, it appears that about 150 wells have received this inhibitor squeeze-type treatment. Approximately 350 separate squeeze treatments have been done in these 150 wells. A breakdown of these 150 wells as to method of production is as follows: gas-lift, 85; natural flow, 15; pumping, 20; and gas condensate, 30. Production from these wells, located in Texas, Louisiana and Arkansas, is both sweet and sour. Some are producing from sand and some from lime-stone formations.

Field Practices for Controlling Water-Dependent Sweet Oil Well Corrosion★,—A Report of Technical Unit Committee T-1C on Sweet Oil Well Corrosion(1), (Compiled by Task Group T-1C-1 on Field Practices(2)

Abstract Field practices used by 19 companies for controlling corrosion in water-dependent sweet oil wells are reported. Limits at which corrosion becomes detrimental are given in terms of percent water produced, iron concentration, coupon corrosion rate, percent wall reduction and frequency of equipment failure. Reports are given of the use of the following devices on flowing wells: injection valves, sidedoor chokes, tapered tubing, and special equipment. Consideration is given also to the minimizing of corrosion in gas lift wells and in pumping wells. Accounts of the use of plastic coated and special alloy tubing are given. Other topics discussed include the use of liquid inhibitors, weighted inhibitors, stick inhibitors, pellet form inhibitors, inhibitor choke, and special techniques.

Study on the Design of Gas Lift Well

When the present writers designed a gas lift installation, they depended on the past experience. Because they have many variables involved in making gas lift calculation. The study of continuous flow gas lift well by F.H. Poettmann and P.G. Carpenter made it possible theoretically to design gas lift installation. The gas lift system is actually in practice at Niigata gas field, Mobara gas field and many other gas fieleds in the country. If writers can apply their theory to designing gas lift well in the gas fields of Japan, the efficiency of gas production from the wells may be increased. The most common type of gas lift method at the gas fields is one in which the gas is injected into tubing and the production returned through the annulus. They studied the gas lift method in which the gas was injected in the annulus and the production returned through the tubing, and the the correlation curve, though essential in their theory, can not be extended to flow through casing size. Making the application of their method, writers must study whether writers can use their method or not.Writers carried out the gas lift tests, in which the gas was injected into the tubing, at 6 inches water well drilled in the Akita University field. The results from the tests were the same as those obtained from the calculation based on their theory. (see Fig. 2) It became clear that their theory could be extended to the gas lift in which the gas was injected into tubing. And writers calculated the correlation factors from the data collected at Niigata gas field, and a plot of the correlation factors versus the product of the hydraulic radius of the annulus and the mass velo city of the fluid is shown in Fig. 3. By using the correlation curve, writers may desigen the gas lift wells in Niigata gas field and may increase the efficiency of the gas production from wells.

Corrosion Control in Gas Lift Wells★

Abstract Conditions in gas lift wells producing appreciable proportions of water are reviewed. Principal corrodent is reported to be carbon dioxide and certain peculiarities of gas lift wells are enumerated. Because of the importance of the ionic composition and chemical content of produced waters, especially those of Gulf Coast wells, the scaling problem associated with these wells is an important consideration in devising inhibitive practices. Because a current statistical analysis indicates about 4000 Gulf Coast gas lift wells probably are already corrosive and because it is expected that 16,000 ultimately will be corrosive the authors point out a potential corrosion damage of as much as $16,000,000 annually. Chemicals used to inhibit corrosion in these wells must have the faculty of penetrating the column of oil and water standing in the well. Laboratory experiments using a model gas lift well and actual produced fluids are described. Some currently available inhibitors have the disadvantage of forming insoluble salts with the calcium and magnesium ions and thus their use is precluded. Furthermore these compounds have not proved stable at reservoir temperatures. Arsenical inhibitors consisting of solutions of sodium arsenite and sodium polyphosphate which proved in tests to be an adequate inhibitor, subsequently were the cause of such difficulties, their use was abandoned generally. Continued tests in two wells indicated they could be used when properly diluted if treatment was continuous and batch fed. Arsenic precipitation was seen as a possible bad effect but reversion of polyphosphates was not encountered. Further there was some suspicion arsenic from these inhibitors resulted in the poisoning of the catalyst in a catalytic cracker. Subsequently it was learned the standard electrical desalting process effectively removes the arsenic. Investigations of organic polar compounds weighted with ethylene glycol resulted in the Continental Oil Company developing its own inhibitors. One of these is being tested in a 7600-foot well.

Corrosion Control in Gas-Lift Wells

Corrosion Control in Gas-Lift Wells