9

11 Gas lift

Gas lift by injecting gas into the production pipe so that the fluid mixture will be lighter, is a common lifting method for productive wells. Few moving parts are located in the well, so the need for intervention becomes small. Gas lift handles water and sand better than other methods.

Gas injection increases the total volume of the fluid mixture, thereby reducing the average density. Reduced density helps to reduce the pressure gradient. However, larger volume also implies greater flow speed that contributes to greater pressure gradient. As long as the density reduction dominates, injection provides less pressure drop. With constant separator pressure, this provides higher production rate.

11.1 Surface facilities

Figure 11.1 illustrates a gas lift system. Usually the gas must be compressed before injection. The gas is distributed between the wells. When the field is producing, gas for injection obtained from the processing plant. At startup, the gas must be obtained from other sources.

Figure 11.1 Compression and injection for gas lift

11.2 The well

Figure 11.2 illustrates a well. The gas is pumped into the annulus at the wellhead. Down hole, the gas flows into the production pipe through a nozzle. The pressure difference across the nozzle may be about one atmosphere. Valves further up the production pipe is used at startup and will otherwise be closed.

.

Figure 11.2 Gas lifted well

Pressure in production tubing and annulus illustrated in figure 11.2 above are calculated for well parameters listed in Table 11.1, with gas injection rate: and oil production rate: . It is assumed that the annular cross section is so large that we can ignore flow friction there.

Table 11.1: Well scenario

Production pipe: length and diameter

L=1600 m, d=70 mm

Annulus : length and diameter

L=1600 m, d=150 mm

Reservoir: pressure, temperature, PI

, , J=20 Sm3/d/bar

Injection valve opening, efficiency fac

dc=12 mm, C=0.9

Fluid: gravities, viscosities

,

Gas content in reservoir oil

Slip parameters

,

Separator pressure

11.3 Safety

With gas in the annulus, we lose the safety barrier that completion fluid otherwise provides. With leakage through the inner casing, gas may then enter between the casings. Outer casings are usually not designed resist high pressure, so that the gas may finally reach the surface. This is obviously very dangerous. It is usually required pressure monitoring pressure between casings to detect such developments early.

If the production pipe or valves leak, the well fluid may flow in the annulus when the gas shut off. This need not be immediately dangerous, but makes the start up more difficult. If the inner casing leaks, it can lead to uncontrolled blowout.

11.4 Oil rate with gas lift

We can calculate the tubing intake pressure by integrating along the pipe

The bottom well pressure estimated from the reservoir to the well:

With no restrictions between well bottom and tubing inlet, these must be equal:, such that

(11-1)

For a given gas injection rate, the resulting oil production must be such that (11-1) is fulfilled.

11.4.1 Numerical solution

Equation (11-1) can be solved by numerical integration of the pipe flow equation and NR-iteration to determine the oil rate. Figure 11.3 illustrates the relationship: qo(qg) for the scenario in Table 11.2. Red line indicates instability, according to criteria developed in Chapter 11.6

Figur 11.3 Oil production depending on gas rate, numerisk løysing

Figur 11.3 estimates max production: 250 Sm3/d reached at gas rate . Somewhat larger gas rate will probably be necessary to achieve stability

11.4.2 Analytical approach

With the following simplifications can (11 to 1) be solved analytically

a) Averaged volume flows: og: a) Volume flow of gas much larger than of oil: , so that:

c) No slip, so that:

d) Mixture density primarily due to liquid content:

e) Linearization of the integral in (11-1):

Volume flow oil production pipe can then be expressed explicitly as in (11-2) below. Inflow rate is here related to oil flow:. Volume factor, density and flows related to average conditions along the production pipe

(11-2)

This analytical formula involves several approximation, and less precise prediction should be expected than by numerical solutions of (11-1). Its usefulness lies in showing basic relations between natural parameters, design choices and resulting gas lifted production.

Figure 11.4 illustrates (11-2) for the scenario in Table 11.2. When density is estimated neglecting slip, and slip still occurs, the interfacial friction should be included in the friction factor, here assumed: fm = 0.04. (By this, the friction factor quantifies irreversible energy transfer, while pressure and height terms quantify reversible energy transfer. This is thermodynamically more consistent.)

Figure 11.4: Oil production for different gas rates, analytic approximation

At high gas rate is figure 11.4 in reasonably consistent with the numerical solution, Figure 11.3. This is reasonable since the analytical solution estimates velocity by gas flow alone. For smaller rates, there is not true.

11.4.3 Analytical approximation for maximum oil productionMaximum oil production can be estimated by derivative: dQo / dQg = 0. Differentiation of(11-2), but will provide 4th-degree equation. Simplification of (11-2) by neglecting gas density contribution to friction provides

This provides optimum gas flow:

inserted into (11-2),provides maximum oil flow.

At surface conditions

(11-3)

To arrive at (11-3), we have utilized the relationship: . This follows from the black oil model.

Optimal gas injection rate corresponds to optimal gas flow, corrected for injecting gas dissolved in the oil phase. At surface conditions, optimum injection rate may then be expressed as

(11-4)

Rs here denotes gas solubility at pipe average conditions, similar to (11-3), while: Rsr, denotes gas content in the oil reservoir

For the scenario above gave (11-3) and (11-4) estimates: and , somewhat higher than from the numerical solution, Figure 11.3.

11.5 Start up

11.5.1 Closed in well

When the well is shut in, the bottom hole pressure equal to the reservoir pressure. This is greater than the bottom hole pressure during production. Starting a closed in well thus required more injection pressure than when the well produces.

Figure 11.4 illustrates a closed well with atmospheric tubing head pressure and gas filled annulus. The oil level is at 1,300 m (If a valve leaks, the oil level will be equal in the annulus and production pipe.) For gas to flow through the injection valve, the pressure in the bottom of the annulus is raised to 100 bar. The purpose of the start-up valve is to be able to start the well with the gas pressure only slightly above that required for stable production.

Figure 11.5 Before start up

Gas lift valves are often placed in wider sections of the production pipe (side pockets), Figure 11.6. The valves can then be replaced by the string operations. Valves may be replaced with blind plugs.

Figure 11.6 Gas lift valve in side pocket mandrel

11.5.2 Startup valves

Figure 11.7 illustrates a pressure-operated valve. The pressure in the bellows: pd works in the area: Ab and provide the force: Fc=pdAb, possibly supplemented by springs. When the valve is open, the annular pressure: pg works on the same area and provides the force: Fo = pgAb. To keep the valve open this must exceed the closing force. By setting the pressure in the bellows, the valve can be set to close at the desired annulus pressure.

When the valve is closed, pressure in the production pipe: pt acts on the area Ap. The area the annulus pressure acting on is correspondingly reduced. (Figure 11.6 illustrates a valve seat without area, as approximation.) When the pressure in the production pipe is smaller than in the annulus, larger gas pressure is required to open the valve than to keep it open. This prevents the valve from opening and closing, "chattering", by small variations in annulus pressure.

Figure 11.6 Prinsipal sketch for pressure operated gas lift valve

Check valve prevents well fluid flows into the annulus when the well is shut off. The choke limits gas inflow through the valve.

11.3.3 Start up

Figure 11.8 illustrates a case where gas is injected through the middle valve, such the gas content in the fluid column above increases and the well pressure decreases. When the bottom well pressure drops below the annular pressure, gas will begin to flow through the lower injection valve and the start up completed.

Figure 11.8 Start up, injection through the middle gas lift valve

11.4.3 Gas lift design

With gas lift design, we normally understand to decide the location, dimensions and adjustment of the valves. The continuous injection valve will always located as deep as possible.

Figure series "1-13" - "1-21" below is taken from Schlumberger / 1999 /. The most unfavorable start-up scenario is that both the annulus and the tube are filled with supplemental fluid, illustrated in 1-14

Figure 1-14 shows initial gas injection. Liquid is pressed into the production pipe and out, but the gas in the annulus has not reached the top valve

In Figure 1-15, the gas has reached the top valve and begins to flow into the pipe. This reduces the pressure gradient and fluid begins to flow from the reservoir

Figure 1-16 shows established gas lift through the upper valve with significant reduction of the pressure gradient therefrom and up, falling bottomhole pressures and inflow from the reservoir. This causes the liquid level in the annulus to continue to sink

In Figure 1-17, the liquid level has descended down to the next valve, so that gas now also flows through it. The gas will now affect a larger part of the production pipe

In Figure 1-18, the upper valve has now closed so that all gas is now flowing through the next. It makes the promise more effective; Bottom pressure drops and fluid level sinks

--- till it reaches next valve

Figures 1-20 show established injection through third valve. The fluid level has now sunk to about 11,000 feet. This is not enough to reach the fourth valve.

Figures 1-21 illustrate wellhead pressures during startup. The gradual reductions are probably made to close pressure controlled start valves as the liquid level in the annulus decreases.

Figure 11.9 summarizes the design procedure as follows from the above illustrations. Static fluid pressure is assumed in the annulus: p(D)=pth+ L gx D (unloading gradient). According to the figure will injection pressure: pgi push the fluid level down to 2400 feet, and the first valve should therefore be placed there and close when the injection pressure falls below: pgi. When gas flows in at 2400 feet, the flow above will be oil and gas and the pressure profile approaches the "design gradient". The pressure will then fall and the fluid level in the annulus will sink further down to 3950 feet, so that the next valve should be placed there. When gas also starts to flow through this, the injection pressure can be reduced so that the 1st valve closes. Further inflow will now take place through the 2nd valve; Until 3rd valve is freed, etc.

Figure 11.9 Locating start up valves

Gas injection through the first start up valve will reduce the pressure gradient up the production pipe (equivalent: blue curve in Figure 11.7). This pressure gradient can estimated for gas and liquid rates considered. In Figure 11.8 this is called "design gradient." From the figure it follows that with design gradient over valve and static liquid gradient below, the liquid level in the annulus will drop to below 3900 feet. Next boot valve should then be placed there. When the gas flows trough this valve, the pressure in the annulus decreases so that the upper valve closes.

Location of startup valves down follows the same sequence. This would ensure startup, and provide business for valves manufacturers

11.6 Dynamics and stability

11.6.1 Observations

Figure 11.10 illustrates pressure in well and annulus for stable production, Heidrun A23. Pressure and temperature are measured at tubing head, wellhead and downhole. The curves are calculated with the stationary flow model and black oil correlations. Drift flux is calculated by equation (9-23): . With Co = 1.27 and vo = 0.1, the calculation matches measured downhole pressure

Figure 11.10 Stable produksjon Heidrun (data provided by Equinor ASA)

Figure 11.11 illustrates stable gas lift. The rates are not constant, but the variations are relatively small with stochastic distribution. This is common for multiphase flow

Figure 11.11: Stationary gas lift

Figure 11.12 shows measured pressure variation when production changes from stationary to oscillating. Production was long stable, but at time: t=50 a disturbance occurs and eventually develops into stable oscillation with period: T = 9.5 minutes.

Figure 11.12 Pressure variations

Kinematic wave velocity from injection point to outlet is estimated: 3.7 m / s, corresponding to time delay: t = 8.2 minutes between injection and outlet, thus close to observations. This suggests propagation of varying gas fraction as cause of instability. The pressure drop across the injection valve is close-to critical, so the gas injection rate is largely insensitive downstream pressure variations. However, constant gas inflow from the valve will lead to varying gas fraction if tubing flow velocity varies.

Figure 11.13 shows measured rates over the same time interval.

Figure 11.13: Rate variation

The examples above showed oscillation period corresponding time to flow from downhole injection point to tubing outlet. Such time scale is consistent with variations propagating along the tubing as kinematic waves. Pressure waves propagate much faster and cause much faster oscillations.

11.6.2 Variation concept

Figure 11.14 illustrates a variation concept supported by the above interpretation:

When mixture with large liquid fraction flows out, the average density in the production tubing decreases, so that the downhole pressure decreases. The inflow of oil from the reservoir and gas from the annulus will then increase. This will change the inflowing liquid fraction. In addition, greater influx of gas will gradually decrease from the annulus pressure, so that the gas flow again decreases. As the changed faction flows out, this will again affect the inflow. If such changes reinforce each other, this will lead to persistent oscillation.

Large pressure drop over the downhole injection valve will make the gas flow less sensitive to well pressure. But even with constant gas inflow, velocity variations in the tubing will cause varying gas fraction. So critical pressure drop across the injection valve does not guarantee dynamic stability.

Figure 11.14 Oscillating gas lift

11.6.3 Dynamic model

Stationary flow of liquid

The inflow is described by (1-1), re-written below

(11-5)

Stationary inflow of gas

The influx from the annulus to the tubing may be described by the orifice relation

(11-6)

The above relationships are pseudostatic; does not contain time explicitly. But they predict how the pressures are affected if the rates change over time

Mass balance annulus

Pressure in a gas filled annulus follows the general equation of state: . Different inflow outflow will cause mass change: , so pressure change in the annulus is linked to the inflow and outflow

(11-7)

Mass balance production pipe

Addition of continuity equations (10-7), (10-8) provides:

Integrated along the tubing :

The inflow will be gas from the annulus and liquid from the reservoir. The outflow will be a mixture of speed: and density: .

Density change will affect well pressure; here expressed by integrating the pipe flow equation from the outlet and down to the bottom: .

Differentiation of the well pressure equation above, inserted density change from the integrated continuity equation, relates the change in well pressure to the inflow and outflow

(11-8)

reservoir response

Gas lift as illustrated above can be expressed as constant average pressures and rates, with dynamic -contribution (perturbation). For constant well pressure: pw, the actual well pressure can be written: ; and rate:. Short-term changes around the mean will not affect reservoir pressure. Inserted in (11-5) gives

(11-9)

gas inflow response

The inflow from the annulus is described with (11-6). Perturbation of pressure and rates then gives

(11-10)

Here, the density: : g and the flow rate: Qg will be known from the stationary resolution that defines the initial state. Equation (11-9) and (11-10) then provides the relationship between the changes:

Annulus response

We will assume constant gas injection to the annulus: . Perturbation of (11-7) gives

(11-11)

Tubing response

We assume that the outflow velocity change immediately upon changed inflow: , while mixture density is unaffected until change of the inflowing fraction reaches the outlet: and . We ignore changes in friction loss: . Superficial speed is expressed as volume flow / cross-section: ,. Perturbation of (11-8) then gives

(11-12)

The responses (11-9) - (11-12) provide 4 relationships between the changes: and. We can thus loose these and thus predict dynamic response for the gas lift system. We can also develop the stability criterion below

11.6.5 Stability criterion

If a well pressure drop:pw reduces the inflow of oil relative to gas: , this will reduce the flowing gas / oil ratio and hence the density of the mixture flowing into the well. The well pressure will then rise to stabilize the system

If we assume constant annular pressure: pa=0 and enter the equations (11-9) and (11-10) into: , this gives

(11-13)

However, pressure in the annulus will fall. If it falls faster than the pressure in the well: , the gas inflow will reduce and the well stabilize. Equations (11-11) and (11-12) set into this, combined with (11-13) gives the stability criterion

(11-14)

The criteria above indicate how changes in design and operating conditions affect stability. For example, smaller annulus: Va and larger gas injection: Qg, provide better stability. Smaller orifice opening: Ac will also work stabilizing The oil rate: Qo is not a free variable but can be calculated from well parameters, which also includes design.The criterion above was developed by Asheim / 1988 /, based on Hjalmar's stability model for air-lift pumping / 1973 / and Fitremann's gas lift / 1985 /. Modifications have been made b. a of Alhanati & al / 1993 /, Fairuzov & al / 2004 /, Poblano & al / 2005 /.

Not lectured in 2018

11.6.6 Prediction of dynamic response

Responses (11-9) - (11-12) provide 4 relationships between the changes. Here are chosen to use (11-9) and (11-10) to eliminate rate variations: from (11-11) and (11-12). This gives 2 relationships between pressure changes: ; in matrix form

(11-15)

Where coefficients contain initial pressures and rates and well parameters; constants known from the stationary solution

Dynamic stability requires negative real component of the eigenvalues, Hirsch & Smale / 1974 / and is achieved for: . It is easy to verify that this corresponds to the stability requirement: F2> 1, equation (11-11) above. In addition, solution of (11-15) predicts oscillations at frequency:

11.6.7 Numerical examples

The examples below are based on the well scenario Table 11.1, with gas injection rate: 75 000 Sm3 / d. Solution by (11-2) gave the oil rate 289 Sm3 / d. Coefficient estimates: aw = 0.00647, ag = 0.00825, c = 0.00772, and delay t = 5.3 minutes. Real part of the eigenvalues: aw -c = -0.00125, thus dynamic stability predicted

Figure 11.15 illustrates pressure fluctuations predicted by numerically solving (11-11), with delayed response neglected. Initially applied deviations decreases over time

Figure 11.15: Dynamic response, delayed response neglected

Figure 11.16 illustrates pressure variations predicted with delayed response included. The deviations now increases with time. The oscillation period is 15 minutes, greater than the delay: t but of comparable order-of-magnitude.

Figure 11.15: Dynamic response, delayed response included

Dynamic response may also be predicted by numerical simulators, by discretization in time and space, Hu & Golan / 2003 /. This can be seen as expanding the matrices in equation (11-15). It is then possible to include several details, but corresponding harder to interpret the results.

11.7 References

1973 Hjalmars, S.

“The Origin of Instability in Airlift Pumps”

J. of Applied Mechanics, June 1973, 399

1974 Hirsch, M.W., Smale, S.

Differntial Equations, Dynamical Systems, and Linear Algebra

Academic press, Boston 1974

1982 DeMoss, E.E, Tiemann, W.D.:

«Gas Lift Increases High-Volume Production From Claymore Field»

J. Pet. Tech., April 1982, 696

1984-a Grupping, A.W., Luca, C.W.F., Vermeulen, F.D.

“Heading action analyzed for stabilization”

Oil and Gas J., July 23, 1984, 47

1984-b Grupping, A.W., Luca, C.W.F., Vermeulen, F.D.

“These methods can eliminate or control annulus heading”

Oil and Gas J., July 30, 1984, 186

1985Fitremann, J.-M. & Vedrines P.

”Non steady gas-liquid flow and gas-lifted wells”

2nd International Conference on Multiphase Flow, London 19-21 June 1985

1988 Asheim, H.: “Criteria for Gas Lift Stability”

J. Petr. Tech. , November 1988, 1452

1993Alhanati, F.J.S., Schmidt, Z., Doty, D.R., Lagerlef, D.D.:

Continuous Gas-Lift Instability: Diagnosis, Criteria and Solutions.

SPE 26554, Proc. Annual Tech. Conference, Houston, Texas, 3-6 Oct. 1993, 401

1995de Oliveira, A.

Establidade Operacional de Pocos com Gas-Lift Continuo

Dissertation, Universidade Estadual de Campinas, Dec.1995

1996Garnaud, F., Casagrande, M., Fouillout, C., Lemetayer, P.:

New Field Methods for a Maximum Lift Gas Efficiency Through Stability

SPE 35555, Proc. European Production Operations Conf., Stavanger, 1996

1999Asheim, H.:"Verification of Transient, Multi-Phase Flow Simulation for Gas Lift Applications", SPE 56659, Annual Technical Conference, Houston, Texas 3-6 Oct. 1999.

1999 Gas Lift Design and Technology Schlumberger /1999/

2002Dalsmo, M., Halvorsen, E., Slupphaug, O.:

Active Feedback Control of Unstable Wells at the Brage Field

SPE 77650, Proc. Annual Tech. Conf., San Antonio, Texa, 2002

2003Hu, B., Golan, M.:

Gas-lift Instability Resulted Production Loss and Its Remedy by Feedback Control: Dynamic Simulation Results

SPE 84917, Proc. Int. Improved Oil Recovery Conference, K.L.,Oct. 2003

2004Guerrero-Sarabia, I., ., Fairuzov, Y.V.:

Stability Analysis of Gas Lift Wells Used for Deepwater Oil Production

SPE 104037, Proc. First Int. Oil Conf. , Cancun, Mexico, 2004

2004Fairuzov, Y.V., Guerrero-Sarabia, I., Calva-Morales, C., Carmona-Diaz, R.,Cervantes-Baza, T., Miguel-Hernandez, N., Rojas-Figueroa, A.: Stability Map for Continuous Gas Lift Wells: A New Approach to Solving an Old Problem

SPE 90644, Proc. Annual Tech. Conference, Houston, Texas, 26-29 Sept. 2004

2005Hu, B. : Characterization of gas-lift instabilities

Doktoravhandling NTNU, 56, 2005

2005Poblano, E., Camacho, R., Fairuzov, Y.V.:

Stability Analysis of Continous-Flow Gas Lift Wells

SPE Production and Facilities, Feb. 2005, 70

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