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Characterizing Gas-lift Instabilities by Dynamic Simulation
Bin Hu and Michael GolanNorwegian University of Science and Technology
S.P Andersensvei 15A7491 Trondheim, Norway
AbstractCasing heading is a well-known instability for gas-lift production, which is caused by dynamic interaction between flow within tubing and annulus. To suppress casing heading, a venturi type of gas-lift valve is selected in many new gas-lift design, which can easily attain critical gas injection, thus isolate the flow interaction. Unfortunately, some field reports show that gas-lift well can still be seriously unstable even casing heading is eliminated by such a valve. To find out the reason for this, we conduct investigation on the existence of any other type of gas-lift instability by using a commercial available multiphase flow simulator. First, to verify the performance of the simulator, the casing heading problem is simulated. Based on this, a series of simulations, in which gas are critically injected from annulus to tubing, are then carried out. From the simulation, a new type of gas-lift instability called density wave instability, is identified and characterized qualitatively. The possible production loss due to the instability is also investigated. At last, the effect of feedback control as a remediation to the instability is demonstrated. IntroductionGas-lift is one of the most widely used artificial lift method in oil production. Economically optimized gas-lift design requires that gas-lift wells be operated at the up-slope of their lift performance relationship curve[7]. This leads the gravity effect becomes the dominant factor of gas and liquid two- phase flow in the tubing. Two-phase vertical flow under gravity domination is often unstable. This is particularly true in the gas-lift wells.
Casing heading is a typical unstable gas-lift production, which has been observed and studied for some years. It needs two necessary conditions to occur. One is that the two-phase flow in the tubing is gravity dominant. The other relies on the large volume of compressible gas in the annulus. If the port size of the gas-lift valve is not small enough, any pressure perturbation in the tubing will be promoted by the changed gas injection rate accordingly. Assuming that a negative pressure perturbation from its steady state is arbitrarily applied in the tubing side, then gas injection through gas-lift valve will be increased due to the increased pressure difference across the valve. The tubing pressure then will be further decreased due to the increased gas injection since the well is operated at the up-slope of its lift performance curve. This trend will continue
until that the annulus pressure is low enough and gas injection starts to decrease. The pressure in the annulus is reduced due to the out-of-balance between the gas flowing into annulus through the casing choke and the gas flowing out of annulus through gas-lift valve. Unfortunately, this slowing down effect of annulus sometimes can only result in limit cycle rather than stabilized flow. The reason is that the annulus response is much delayed due to its huge volume and the compressibility of the gas. It behaves as a buffer tank in this situation.
The hazardousness of casing heading to operation safety and smoothness has been aware. The previous investigations on casing heading mainly concentrated on its characterization and developing simple stability criteria[1][3][4][6][10][11][18]. The purpose of obtaining the criteria was to avoid casing heading at the design stage of gas-lift. Due to the complexity of gas/oil/water three-phase flow and their PVT properties, even the latest developed criterion is less convincing than dynamical numerical simulator[16] when comparing with field data. In fact, predicting gas-lift instability at its design stage has no too much meaning since the well conditions are always changing.
On the other hand, some researchers try to find out a long term solution by developing new gas-lift hardware. The new type of gas-lift valve based on nozzle venturi principle[17] is a result of this effort. It can easily attain critical flow under small pressure difference for the gas injection and thus suppress the occurrence of casing heading while at the same time maintaining low gas injection cost. Since it was invented, the new valve, which was named as NOVA, has been selected by many new gas-lift designs. It is also used to replace the orifice valve for the unstable wells in operation[14]. But not all the installation of NOVA valve gave a successful story. Eliminating casing heading does not mean assured well stability.
From some North Sea gas-lift wells, it was found that they could be unstable even NOVA valves were used. The same observation also comes from gas-lift wells offshore Lake Maracaibo[14]. These observations initiated a new study in gas-lift instability for the situation when gas injection rate at the bottom of the well is constant and annulus flow is not involved in the dynamics. Why the well is still unstable? Is there any other instability mechanism in the background? If so, what kind of characteristics does it have? These are the questions to
2003 2-Fall Gas-Lift Workshop21st and 22nd, October 2003.
Kuala Lumpur, Malaysia
2 Bin Hu, Michael Golan
be answered in the study. This paper gives the primary simula-tion results that shows density wave instability can occur in gas-lift wells equipped with NOVA valve.
Simulator and its performanceDue to high cost and complexity, it is difficult to investigate the reason of unstable gas-lift production by performing field test or laboratory experiment. Particularly for the new unknown instability, it is almost impossible to identify and characterize it by doing experiments on the real gas-lift well because of the many uncertainties. Thus, using dynamical simulator is more preferable since it is more cost-effective and less risky. With the development of new dynamical multiphase flow simulator, this becomes more and more realistic, specially as a first try in the situation when the problem is new and we do not know too much about it. In this paper, OLGA2000© is selected as our simulation tool. A series qualitative simulation is performed to investigate the existence and characteristics of any new gas-lift instability after NOVA valve is installed.
The simulatorThe objective of developing OLGA was to simulate slow transient multiphase pipe flow such as terrain slugging, pipeline startup and shut-in, flow rate variation and pigging. The first version of OLGA was working in 1983, but the main development was carried out later by a joint research program, involving two research institutions and several oil companies. OLGA is based on an extended two-fluid model, accounting for flow regimes and droplet entrainment and deposition. Correlations for holdup and flow friction are selected based on flow regime considerations. The OLGA model had been tested against experimental data over a substantial range in geometry scale, pressure and variety of fluid[5].
Besides OLGA, there are several other multiphase flow simulators in the market. The dynamical performances of the simulators have been tested and evaluated in different applications and experiments. It was observed that none of the simulators could give satisfied results in all tests[2][15]. To make our simulation investigation results be meaningful and reliable, we take the following methodology in our simulation study. First we use casing heading problem to verify the dynamical performance of OLGA since the basic characteristics of casing heading are already known from previous studies. If OLGA simulation can reflect those characteristics, then we have enough reason to trust the OLGA simulation results from other type of gas-lift instabilities.
Simulation of casing headingA hypothetic well is built within OLGA2000 for simulating casing heading. The well parameters were abstracted from some North Sea gas-lift wells. The main parameters are as follows. Unloading valve is not considered in the simulation.
2048 m in depth 5 inch tubing 10 inch casing 2.75 inch production choke 0.5 inch injection orifice
The reservoir parameters are PR = 150 bara TR = 108 C PI = 26Sm3/D/bar
Since the purpose of this study is just to investigate the dynamical characteristics of the well, we assume that there is no water in the produced fluids. GOR is approximately 80 Sm3/Sm3 for the oil sample used in the simulation.
The hypothetic well has three boundary conditions. In the reservoir side, reservoir pressure, temperature and productivity index are given. On the surface, separator pressure is assumed constant. While at the casing head, there is a fixed gas injection rate. Besides, a steady formation temperature field along the well path is assumed and a constant overall heat transfer coefficient is used. The base case is that production choke is fully open, separator pressure equals 15bara and injection gas rate is 72000Sm3/D.
OLGA2000 has an internal steady-state simulator. In our study, all the simulations are initiated from steady-states. Effects of four factors on casing heading are simulated. These include gas injection rate, size of gas-lift valve, productivity index and choke opening. For each factor, two additional cases are tested upon the base case to see the tendency of stability.
1. Increasing gas injection rate can increase the stability if the well is operated near its optimum gas-lift point. This attributes to two factors caused by increased gas injection. One is the increased friction loss due to increased flow rate in the tubing. Another is that high gas rate can make the flow in the annulus more stiff, thus reduce the delay effect. Figure 1 gives the simulation results showing the change of well bottom hole flowing pressure under three different gas injection rates, in which the first is the base case. The third case has the highest gas injection rate, which is approximately one third higher than the base case rate. It shows that the oscillation amplitude is decreased and frequency is increased when increasing gas injection, and finally the well is stabilized when gas injection rate is high enough.
2. The port size of gas-lift valve has strong impact on well stability. Valve with smaller port size can increase stability since it can suppress big flow variations. Figure 2 shows the time series of bottom hole flowing pressures for three cases with different port sizes, in which the smallest size is 3/8 inch and the biggest is ¾ inch. It is clear that the oscillation amplitude is decreased when using smaller size orifices. At 3/8-inch case, the well is fully stabilized.
3. Productivity index also can change the stability of the well. Since increased gas injection will decrease the hydrostatic pressure drop by decreasing mixture density, a higher productivity index should have a stabilizing effect by supplying more reservoir fluid to
Characterizing Gas-lift Instabilities by Dynamic Simulation 3
compensate the mixture density reduction caused by increased gas fraction. This is also clearly demonstrated by the simulation. Figure 3 shows the effects of productivity index. Increasing productivity index reduces the oscillation amplitude and the well becomes stable when it is big enough. In this simulation, the productivity index of case three is about three times of that in the base case.
4. Choking is the most used pragmatic way of stabilizing unstable wells. The role of choking relies on that smaller choke opening can increase friction loss for the whole system. The lift performance curve at smaller choke opening will become more flat than that at bigger opening. OLGA simulation results on choking effect are given in figure 4. It shows that choking decreases instability. When the choke opening is about 40%, the oscillation amplitude is already significantly reduced. Continuing to close the choke to 20% opening, the well is fully stabilized.
OLGA2000 simulation results successfully demonstrate the main characteristics of casing heading problem. The limit cycle of casing heading process has been clearly reflected by the simulations. There could be some offsets in numbers if OLGA simulation can be compared with field data. But, from the above simulations, we believe that OLGA at least has the capability to qualitatively capture the main dynamics of gas-lift instability. This gives us the confidence of using OLGA in the following investigations since they are rather qualitative than quantitative.
Dynamical simulation studyA similar hypothetic well is built within OLGA when we investigate the new problem. Since gas injection through gas-lift valve is constant, then the flow in annulus and through the valve is dropped from the simulation, instead, a constant gas source is given near the bottom of the well. We also decide to remove all the weak factors from our simulation so that the results are more representative and with common sense. This leads to that air and water are used as test fluids instead of gas and oil, and the system is assumed isothermal. Detailed information of the well and reservoir are
2500m in depth 5 inch tubing PR =50 to 260 bara Psep=10bara PI=34.5Sm3/D/bar or 4e-6kg/s/Pa
The above parameters give the base case for the simulation study, in which choke is removed from the system. Some of the parameters will be changed when studying their effects on stability.
Density wave instabilityA series of simulations are performed with different gas injection rate. All the simulations are initiated from steady-states as we did in simulating casing heading. Stable and unstable productions are judged from the time series of
different variables. If they tend to be a straight line after a period, then the production is said stable. Otherwise, if they develop into limit cycle like we see in casing heading problem, then the production is unstable. From the series of simulation, we can get stability maps for different simulation settings.
The simulation results are quite surprising. We do find instability at the situation when gas injection rate is constant at the bottom of the well. Figure 5 is a stability map for the base case. For a given reservoir pressure, particularly when it is not high enough to overcome the hydrostatic head and make the well naturally flow, three phenomena, indicated as “no production”, “unstable” and “stable production” in the map, can be observed when increasing gas injection rate from low to high. When the gas rate is too low to lift the liquid, gas phase will flow through the liquid and release at the top of the well. The liquid level may be oscillating within the tubing, but no production is observed at the wellhead. This kind of phenomenon is marked by the cross sign on the stability map.If increasing the gas rate to a certain level, a burst-like liquid production is observed. The well starts to produce unstably. Figure 6 gives the out looking of the production at this situation. Long periodic time is its typical characteristic. If continue increasing the gas rate, both the frequency and the amplitude of the oscillation will increase. This is shown in figure 7. The oscillation will become more harmonic-like if the gas rate is increased further as shown in figure 8.
All the unstable cases are marked by black dots on the map. The well will be stable if gas rate is high enough. The stable region is mainly located in the upper right direction on the map. All the stable cases are market with small circles. The stability map is quite representative. If just plot the boundary points between stable and unstable production, we can compare the effects of different well parameters on the stability. These are shown from figure 9 to 12. In those figures, x-axis represents the dimensionless reservoir pressure and y-axis is the gas injection rate. Total system pressure drop divided by hydrostatic head for liquid column filling the tubing gives the dimensionless reservoir pressure.
Figure 9 gives the effect of well depth. It shows the deeper the well, the more the chance for well to be unstable when reservoir pressure is low. Figure 10 shows the effect of system pressure. If the separator pressure is increased from 10bara to 20bara, the unstable region will be enlarged significantly, particularly among the lower reservoir pressure range. Figure 11 gives the stability map for different tubing size. Increasing tubing diameter will tremendously increase the unstable region. Figure 12 shows the choking effect on stability. In the figure, the percentage of choke opening is relative to the cross area of tubing. From 100% opening to 50% opening, we see no clear change in the instability map, but, if the well is choked further, the unstable area will be reduced. Even though choking normally gives stable effect to flow oscillations, it is not that effective in this situation when production rate is low.
4 Bin Hu, Michael Golan
The effect of productivity index on stability is shown in figure 13. High PI value will increase instability at lower reservoir pressure. This result is against our conventional thinking since high PI should give more production and less instability. It is this result that implies us that density wave instability can occur in a well producing depleted reservoir. Since this instability has never been discussed in petroleum gas-lift application, we borrow this name from the similar phenomenon observed in airlift pumps that are often used in the mining industry[8][12].
The explanation of density wave instability is as follows. Since the gas injection rate is constant, then any variation in the liquid inflow to the wellbore will easily result in the density change of the two-phase mixtures in the tubing due to the change of phase fraction. Clearly, the mixture density change will result in the change of hydrostatic pressure drop, thus the total pressure drop, particularly in a gravity dominating system. The initiated mixture density change due to phase fraction variation at the bottom of the well will travel along the tubing as density wave, which sometimes is also called continuity wave or void wave. This density wave does not necessarily introduce instability to the system since the well has a self-controlling effect. This attributes to that any increase in the pressure drop due to increased mixture density will result in the reduction of the liquid inflow and thus the mixture density, and vise versa. But this self-controlling mechanism is more or less delayed due to the dynamic out-of-phase effect between the well influx and the total pressure drop along the tubing. To a certain level, the self-controlling effect breaks down and the well becomes unstable.
To promote the density wave instability, high PI is necessary since an over response of influx can result in a high density change. At the same time, since choke is installed at the end of the flow path, its restrictive function to the influx perturbation started at the bottom is then delayed. This results in that choking is a less effective method in stabilizing the density wave instability. These two aforementioned points are all demonstrated from the simulation.
Production loss due to density wave instabilityBesides the hazardousness of the fluctuation to operation safety and smoothness, the production loss due to instabilities is another important issue for unstable gas-lift wells. The same as casing heading problem, density wave instability can also cause flow rate change compared with steady-state predictions. Figure 14 shows the production rate of unstable production at different gas injection rate. The production rate is normalized to that predicted from steady-state calculation. Reservoir pressure is 90bara for all the simulations. The interesting observation here is that unstable production due to density wave instability not only can reduce the production but also can increase the production if the gas rate is low enough. For an example, according to the simulation result, the well can produce as twice as its steady-state prediction when the well just steps over the threshold from “no production” to “unstable production”.
In most situations, the range of gas rate that can increase production is not of interest in practical gas-lift wells. The normal gas rate is much larger than that. For the high gas rate, production loss rather than gain is often observed as shown in figure 14, in which up to 24% production reduction can occur at a certain gas injection rate. We have even observed that up to 50% production loss is possible from other well settings. The field tail production will be prolonged due to the reduced production rate since it will take more time to get the same recovery. This will tremendously increase the cost of operation. So, whenever gas-lift instability is characterized, the production loss that comes along with it must also be investigated. But in practice, this is often not mentioned particularly when the downstream receiving facility and process can handle the flow fluctuation. Here we want to emphasize the notion that production loss is the norm for oscillating wells and the instabilities have to be seriously treated even when they do not cause any operation problem.
Applying feedback controlRecently, feedback control has emerged as a cost-effective option for stabilizing gas-lift wells[9][13]. For the wells that cannot be stabilized by installing NOVA valve, or are technically and economically forbidden to install NOVA valve, feedback control is an effective option. The following simulation will demonstrate that the production loss is also reduced as an effect of stabilization by feedback control. As indicated in casing heading problem, static choking can only stabilize the well without saving the production loss. Dynamic choking based on feedback control not only can stabilize unstable wells, but also can save the production loss. Thus, the advantage of applying feedback control to suitable unstable wells is promoted.
Only very simple feedback control structure is tested in this paper, in which bottomhole flowing pressure is controlled by production choke. PI controller is selected to carry out the task. The controller settings are determined by following steps. First, the optimum setting of the bottomhole flowing pressure is determined from OLGA steady-state simulation. In fact, the setting should be a lit bit higher than the steady-state prediction. Then the integration time is selected proportion to the period time of the oscillation. A small gain value is determined so that stability can be achieved. The gain value is adjusted by trial-and-error so that the setting of bottomhole flowing pressure is as close as possible to the steady-state prediction and a quick stabilization can be realized.
Figure 15 and 16 show the results of applying feedback control to the case given by figure 7. For control purpose, the choke diameter is selected as only half of the tubing diameter. Even so, when it is fully opened, the observed oscillation is quite close to the situation in figure 7, in which no choke is installed. The reason for this has been discussed in last section. The controller is started after 5.5 hours from the beginning of the simulation. Figure 15 shows the choke opening variation. It finally approaches 40% when the well is stabilized 10 hours later after the controller is started. Figure 16 shows that the stabilized production rate is also quite close
Characterizing Gas-lift Instabilities by Dynamic Simulation 5
to steady-state prediction when choke is fully opened. In fact 96% normalized rate is obtained after stabilization by feedback control. This is marked in figure 14 by a black dot. Comparing with the case without using feedback control, in which the rate is only 76%, thus, 20% production is saved.
If keep the choke opening determined by feedback controller and switch back to manual control, the well is unstable again even the choke opening is only about 40%. This is shown in figure 17. Comparing the simulation results in figure 7 and figure 17, we see the instability is reduced a lit bit as an effect of static choking.
Conclusions1. Density wave instability can occur in gas-lift wells
equipped with NOVA valve, particularly when the reservoir is depleted and gas injection rate is low.
2. Unstable gas-lift can definitely result in production reduction. Around 20-40% of production loss is observed due to gas-lift instability for typical well settings in our simulations.
3. Static choking can normally stabilize the gas-lift at a cost of losing production. But dynamic choking not only can stabilize the gas-lift wells, but also can reduce the production loss. In the simulated cases, the well produces closely to its steady-state predictions when feedback control is applied.
4. The performance of dynamic simulator, OLGA2000, has been verified by reflecting the main characteristics of casing heading problem. It shows promising capability in simulating gas-lift instabilities.
AcknowledgementThis research is supported by PETRONICS project sponsored by ABB, Norsk Hydro AS, Norwegian Research Council and Norwegian University of Science and Technology. Scandpower Petroleum AS is acknowledged for offering OLGA2000 academic license.
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6 Bin Hu, Michael Golan
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Characterizing Gas-lift Instabilities by Dynamic Simulation 7
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8 Bin Hu, Michael Golan
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0,5
0,6
0,7
0,8
0,9
1,0
0,0 0,1 0,2 0,3 0,4 0,5 0,6 0,7 0,8 0,9 1,0
(PR-Psep)/ρlgL
Gas
inje
ctio
n ra
te (x
6700
0Sm
3 /D)
4e-6kg/s/Pa8e-6kg/s/Pa2e-6kg/s/Pa
Figure 13. Effect of PI on stability.
0.0
0.2
0.4
0.6
0.8
1.0
1.2
1.4
1.6
1.8
2.0
1.0E+04 1.5E+04 2.0E+04 2.5E+04 3.0E+04 3.5E+04 4.0E+04 4.5E+04 5.0E+04 5.5E+04 6.0E+04
Gas injection rate (Sm3/D)
Nor
mal
ized
pro
duct
ion
rate Open loop dynamical simulation results
With feedback control
Figure 14. Production loss due to density wave instability.
0.0
0.2
0.4
0.6
0.8
1.0
1.2
0.E+00 1.E+04 2.E+04 3.E+04 4.E+04 5.E+04 6.E+04 7.E+04 8.E+04 9.E+04 1.E+05
Time (s)
Cho
ke o
peni
ng (-
)
Figure 15. Variation of choke opening before and after controller is started.
0.E+00
1.E+06
2.E+06
3.E+06
4.E+06
5.E+06
6.E+06
7.E+06
8.E+06
9.E+06
1.E+07
0.E+00 1.E+04 2.E+04 3.E+04 4.E+04 5.E+04 6.E+04 7.E+04 8.E+04 9.E+04 1.E+05
Time (s)
P wf (
Pa)
0
200
400
600
800
1000
1200
1400
1600
1800
2000
Prod
uctio
n ra
te a
t wel
lhea
d (m
3 /D)
Bottomhole flowing pressureProduction rate at wellhead
Figure 16. Variation of pressure and production rate before and after controller is started.
0.E+00
1.E+06
2.E+06
3.E+06
4.E+06
5.E+06
6.E+06
7.E+06
8.E+06
9.E+06
1.E+07
0.0E+00 5.0E+03 1.0E+04 1.5E+04 2.0E+04 2.5E+04 3.0E+04 3.5E+04 4.0E+04
Time (s)
P wf (
Pa)
0
150
300
450
600
750
900
1050
1200
1350
1500
Prod
uctio
n ra
te a
t wel
lhea
d (m
3 /D)
Bottomhole flowing pressureProduction rate at wellhead
Figure 17. Unstable production when controller is switched back to manual control.
