Gas Rate, GLR and Depth Sensitivities of Gas Lift...

International Journal of Engineering Technology, Management and Applied Sciences

www.ijetmas.com July 2015, Volume 3, Issue 7, ISSN 2349-4476

138 Pshtiwan Tahsin Mohammed Jaf

Gas Rate, GLR and Depth Sensitivities of Gas Lift Technique:

A Case Study

Pshtiwan Tahsin Mohammed Jaf Petroleum Engineering Department,

Faculty of Engineering, Koya University, Kurdistan Region, Iraq

ABSTRACT In petroleum industry, various problems may arise during production operations such as reduction in desired oil rate

due to water conning and lifting problems. Gas lift optimization is considered as a prestigious technique for preventing

such problems.

This work is carried out as a consequence of low production problems in one of the oil fields in Iraq. The name of the

field is not mentioned in this work due to the confidentiality of publication and well is named as JAF. Currently oil is

produced in JAF well through gas lift technique, while in other wells oil is produced by their own reservoir pressure.

Before implementing gas lift optimization, the average oil production rate for JAF well was around 1700 (bbl/day), with

relatively low drawdown pressure (psig) between average reservoir pressure and bottom-hole flowing pressure. Thus, to

optimize the production, this well is modelled in PROSPER program, through entering row field data of both reservoir

fluids properties and well testing data for PVT matching and generating IPR + VLP for the well.

In this paper, the JAF well has been modelled in PROSPER step by step. For VLP correlation comparison, Petroleum

Expert-2 was found very close to well test data for all vertical/tubing performance. While for matching pipe correlation

Beggs and Brill correlation is found the best fit correlation for production and flow line test. Design injection pressure

is inputted based on the available source supply and considering bubble point pressure as well.

The sensitivity results, through which maximum oil production rate is achieved as 2343 bbl/day for JAF well at gas lift

injection rate of l.75 MMscf/day.

In addition, maximum and optimum GLR for the well is determined under fixed injection rate of 1.35 scf/day of GasLift

gas rate based on the selected correlation for analysing injected GLR sensitivities and the result is 451 scf/stb for JAF

well.

Finally, optimum injection depths for fixed gas injection rate in MMscf/day for this well is obtained as 2250 ft.

Keywords

Gas Lift, Gas Rate, GLR, Depth, Optimization, Sensitivity, Pressure.

1 INTRODUCTION

1.1. Brief history Field X is a super-giant field and mainly limestone reservoir with fold hydrocarbon trap (Anticline fold) and its rock type is Dalmatic limestone which is characterized with natural fracture. The reservoir petro-physical properties are ranged between (5-44) md for average permeability, between (13% - 26%) for water saturation and between (18% - 27%) of average porosity in matrix. The oil column thickness is about (60-90) meter with large gas cap and Aquifer, the estimated Gas oil contact at depth 600 ft MSL and estimated oil water contact at 740 ft MSL. For proceeding to produce from the field, it was planned to install a gas lift system for the wells which do not produce in a desired rate relative to other high producer well. To meet the requirements demanded by the local government.

1.2. Scope of Work and Paper Objectives The objective of this paper is to analyze the oil production rate variation by implementing the gas lift artificial method for a well named here as JAF of X field with two different domes. The work is performed by the application of PROSPER software package. Furthermore, the objective of this study is to provide some decision supporting document and evaluating each of the scenarios in detail through using advanced software packages to match the data history and predict simulation results. Consequently, simulations based on the field data will give an indication of what rates can be produced and the different solutions will be recommended. A complete production analysis will be




developed by running a simulation program in PROSPER for individual well system and the maximum oil production rate that could be achieved for the whole production system.

1.3. Pressure and Flow Rate Profile Most of the wells are completed at a depth that should flow for a period of time after they begin put in production. This will not be continuous because the energy will be spent and at some time there will not be sufficient drive force to lift the fluid to the surface. Consequently, the well ceases to flow and the operating company will be tempted to put the well on one of the forms of artificial lift to provide a good lifting energy (Lake, 2010). Figure 1 illustrates the reasons why it is required to lift the hydrocarbons artificially. Through looking at this figure, wells normally can produce by their own reservoir pressure only for a specific period of time.

Figure 1: Pressure versus Flow Rate Profile (Lake, 2010).

Periodically, the required quantity of oil will not be achieved at the surface facilities, mainly because of the following factors:

Low reservoir pressure

Heavy oil (high density fluids)

Scale liquid around the wellbore

Skin damage around wellbore

Poor completion and reservoir rock properties Water conning Therefore, the company will be tempted to optimize the production through the stimulation or by artificial lift systems, for example, gas lift system (Hadiaman, 2011).

2. GAS LIFT METHOD Gas lift is one of artificial lift methods, through which high pressure gas is injected continuously or intermittently into the well through casing and U-Tubed to tubing. Thus, resulting in the reduction of the hydrostatic pressure of the heavy column of the fluid and reducing bottom-hole flowing pressure. The purpose of gas lift installation also to bring hydrocarbons to the surface at a desirable quantity while keeping the bottom-hole pressure at a value that is small enough to provide high drawdown pressure within the reservoir (Beggs, 2003) Thus, gas lift method is where relatively high pressure gas is used as lifting agent through a mechanical process. The installation of the gas lift system is required when the pressure of the reservoir is not quite enough to maintain the oil production with sustainable economic return. This system is widely applicable for the oil fields where the increasing water cut or decreasing reservoir pressure eventually causes well to cease its natural flow (Ahmed and McKinney, 2004). 2.1. Gas Lift Optimization The operation of the gas lift system is very similar to the normal production, because there is no any change in the design configuration of the production system in terms of size and design. The artificial method will be




through lifting the fluid to reduce the bottom hole pressure as well as the hydrostatic pressure gradient on the wellbore. A simplified diagram of a particular gas lift system is shown in the below figure (Guo, Lyons and Ghalamber, 2007).

Figure 2: Pressure relationships in a continuous gas lift (Guo, Lyons and Ghalamber, 2007)

2.2. Gas Lift Well Performance Analysis Noda analysis is used to analyse the gas lift well performance, the following processes should be done to analyse the system.

Select the operating gas lift to be analysed.

Select the node location that is most sensitive to change.

Develop the relationship between the inflow and flow of the node.

Calculate pressure drop versus flow rate for all components.

Determine the effect of changing characteristics of the selected node (gas lift valve).

Optimise the production system. To follow the above mentioned steps, it is more convenient to allocate gas lift working valve as the posistion of the node. Thus, the node pressure will be the pressure at the tubing exactly in the depth where the valve has been installed symbolised as Pv. Hereby, the outflow and inflow would be: Inflow into the node (at the gas lift valve depth)

(equ.1)

Where, Pv is the pressure at the valve (psi) Pres is the reservoir pressure (psi) P res is the pressure difference across the reservoir (psi) P tbg is the pressure difference across the tubing string (psi) Outflow from the node;

(equ.2)

Where,

is the pressure at the valve (psi)

is the wellhead pressure (psi)

is the pressure difference across the tubing string (psi)

As the depth of gas injection point is changing with the type of design and at the same time there are more than two valves usually installed into the wellbore. So, it is better to select the P wf as the node pressure. A digram between the Pwf and flow rate can be drawn, the effect of carrying out sensitive in the gas liquid ratio




will affect the outflow, but inflow will remain constant. This is because, the injection gas will affect the fluid above valve only. The below figure illustrates more about the effect of changes in GLR.

Figure 3: Effect of gas rate on outflow (Beggs, 2003)

Increasing the GLR, the bottom hole flowing pressure decreases, consequently more liquid (oil) will be delivered to the surface. The GLR has a limit, because the injection pressure should be designed in a manner that will not affect the reservoir pressure, i.e. avoiding the reverse flow from the wellbore into the reservoir. Furthermore, any extreme injection pressure might kill the well and stop the fluid flowing (Brown, 1984).

2.2.1. Gas Injection Rate To determine the optimum gas rate, it is required to select a node in the reservoir while the gas lift valves are also within the vertical system. The equations for inflow and outflow are expressed as follows:

(equ.3)

(equ.4)

Where, Equation 3 is the inflow to the node and 4 is the outflow from the node (valve) Pwf is the bottom-hole flowing pressure (psi)

is the reservoir pressure (psi)

is the seperator pressure (psi)

is the pressure difference within the reservoir (psi)

is the pressure difference within the flow line (psi)

is the pressure difference at the tubing above the GL valve (psi)

is the pressure difference at the tubing below the GL valve (psi)

The inflow into the node ( nd will not be affected by the rate of

injection gas, but the downstream flow relative to the valve will be affected. Thus, the pressure drop across

flow line ( and pressure drop across tubing above valve will vary with the change of injected

GLR. Consequently, the different outflow line will be produced for each injected GLR (Economides, Hill and Ehlig, 1994). As shown in figure (3), the intersections of the inflow and outflow curves indicates the produced liquid for different injected GLR. Equation (5) is used to determine gas injection rate for a continuous gas-lift, when the system rate capacity is known (Beggs, 2003).

(equ.5)

Where,

is the gas injection rate (MMscf/day)

is desired liquid production rate (bbl/day)




is th producing gas-liquid ratio above point of gas injection (scf/bbl)

is the producing gas-liquid ratio below point of gas injection (scf/bbl) Under static conditions, the pressure gradient in the tubing-casing annulus can be written as:

(equ.6)

Where, Pso : Surface operating pressure (psi) and PV : tubing pressure at the gas lift valve (psi)

: gas gravity (air=1) and : True vertical depth to injection point (ft) Zavg and Tag: Average compressibility factor and average temperature (ºR) respectively

2.2.2. Effect of Injection Gas Rate Not only the required rate of injected gas should be calculated, but also the optimum amount of injection gas should be determined through plotting a graph between the qgas-injection versus the qLiquid-produced as shown in the figure (4) through which maximum amount of production rate should be avoided to reduce the probability of killing the well. Nevertheless, the economical amount of injection rate can be touched through the same graph to achieve a sustainable production system (Beggs, 2003).

Figure 4: Effect of Gas Injection Rate On Production (Beggs, 2003)

2.2.3. Effect of Injection Depth The second category which should be considered is the depth of injection. For that reason, a graph would be produced between gas injection rate versus qL-production with the corresponding injection depth. As a result, different curves of production rate can be obtained with relative to the change in the depth of injection but at constant injection rate. From figure (5) it is clear that by changing the depth for the same amount of injection rate, the production rate will increase (Hall and Decker, 1995).

Figure 5: Effect of Injection Depth on Production (Beggs, 2003)

3. WELL MODELLING In PROSPER Modelling a gas lift system is easily provided by PROSPER simulator. PROSPER separates the various aspects of the well that contribute to the overall production performance. After modelling each aspect, it has the ability to verify them by performance matching. The purpose of performance matching is to make sure




those calculations and input data are in the right position. PROSPER is able to model a well in different scenarios to obtain the upstream accurate information based on the surface data. The below tables in the next pages are the key input data which required while modelling a continuous gas lift system concerning a well. For example, in this paper JAF well has been brought into analysing and simulate the effect of gas lift system on its production rate. The row field data for this well have been brought for analysis in this paper. The well is being proposed to put under gas lift optimisation, because its production rate declined to unwanted level. PVT data, IPR entry data, Downhole data (deviation survey and equipment) and well testing data (BHCIP, BHFP and PI) for the well are provided. These data are arranged separately based on the PROSPER simulator input requirement and all units will be field unit. This is to give better understanding on correlation and matching with reality.

3.1. Well Data

Table 1: PVT Data of the Reservoir Fluid

Parameters Quantity Units Solution GOR 212 scf/stb

Oil Gravity (API)º 34 API Gas Gravity 0 -

Water Salinity 0 ppm Gas Impurities 0 %

Bubble Point Pressure at MD temperature 950 psig Oil FVF at MD Temperature and Pressure 1.138 stb/bbl

Oil Viscosity 1.34 cp

Table 2: IPR Data

Parameters Quantity Units Reservoir Pressure 1200 psig

Reservoir Temperature 160 °F Water Cut 15 %

Total GOR 237 scf/stb

Table 3: Downhole Data

Measured Depth (MD) True vertical Depth (TVD) ft ft

0 0 1670 1670

Table4: Downhole Equipment

Well Name

Tubing Dimensions Casing Dimensions Total Depth

ID (inches)

Depth (ft RTKB)

ID (inches)

Depth (ft RTKB)

(ft RTKB)

JAF 3.5 950 7.00 990 1670

Table5: Well Test Data

Test Type BHCIP BHFP

Pressure Differential

Rate Productivity Index (PI)

Water Cut

pisg pisg pisg bopd stb/day/psi percent

Production 1169 1010 159 1700 9 15




3.2. Outline of the Calculation Steps The below flow chart illustrates an outline of the calculation processes that are required to model a system analysis using PROSPER:

Figure 6: PROSPER outline calculation processes

4. RESULTS, SENSITIVITIES ANDDISCUSSION

4.1. System Capacity Prior to Gas Injection PROSPER can calculate the system (VLP+IPR) or system capacity for each well before any gas being injected. This gives an indication of the original well capacity to deliver hydrocarbons to the surface based on the natural BHP. The figure below is the plot between IPR versus VLP for the well, the intersection of these two curves is called the solution point for the well.




D:\Salford University\Masters Project\Simulation Results\2\1\Well Number 1.Out

6.86707 1720.55 3434.22 5147.9 6861.58

0

354.795

709.59

1064.39

1419.18

Inflow (IPR) v Outflow (VLP) Plot (Well Number 1 13/06/2013 - 21:00:21)

Liquid Rate (STB/day)

Pre

ssu

re

(psig

)

PVT Method Black OilFluid Oil

Flow Type TubingWell Type Producer

Arti ficial Lift Gas Lift (Continuous)Lift Type No Friction Loss In Annulus

Predicting Pressure and Temperature (offshore)Temperature Model Rough Approximation

Company University of SalfordField Field A, Dome B

Location Kurdistan - North of IraqWell Well Number 1

Analyst Farhad KhoshnawDate 10/06/2013

Top Node Pressure150.00 (psig)Water Cut15.000 (percent)

Bottom Measured Depth3449.9 (feet)Bottom True Vertical Depth3449.9 (feet)

Surface Equipment Correlation Beggs and Bri l lVertical Lift Correlation Petroleum Experts 2

Solution Node Bottom NodeLeft-Hand Intersection DisAllow

Inflow Type Single BranchCompletion Cased Hole

Sand Control NoneGas Coning No

Reservoir Model PI Entry

Compaction Permeabil ity Reduction Model NoRelative Permeabil i ty No

Absolute Open Flow (AOF)6867.1 (STB/day)Reservoir Pressure1200.00 (psig)

Reservoir Temperature200.00 (deg F)Water Cut15.000 (percent)

Solution Point

Liquid Rate 1794.9 (STB/day)Oil Rate 1525.6 (STB/day)

Water Rate 269.2 (STB/day)Gas Rate0.36157 (MMscf/day)

Injection Depth 1895.0 (feet)Solution Node Pressure1000.57 (psig)

dP Friction 21.28 (psi)dP Gravity 824.36 (psi)

dP Total Skin 0 (psi)dP Perforation 0 (psi)

dP Damage 0 (psi)dP Completion 0 (psi)

Completion Skin 0Total Skin 0

Wellhead Liquid Density 54.251 (lb/ft3)Wellhead Gas Density0.55819 (lb/ft3)

Wellhead Liquid Viscosity 2.7201 (centipoise)Wellhead Gas Viscosity0.011861 (centipoise)

Wellhead Superficial Liquid Velocity 2.450 (ft/sec)Wellhead Superficial Gas Velocity 6.912 (ft/sec)

Wellhead Z Factor 0.9748Wellhead Interfacial Tension15.9217 (dyne/cm)

Wellhead Pressure 150.00 (psig)Wellhead Temperature 128.66 (deg F)

First Node Liquid Density 54.251 (lb/ft3)First Node Gas Density0.55819 (lb/ft3)

First Node Liquid Viscosity 2.7201 (centipoise)First Node Gas Viscosity0.011861 (centipoise)

First Node Superficial Liquid Velocity 2.450 (ft/sec)First Node Superficial Gas Velocity 6.912 (ft/sec)

First Node Z Factor 0.9748First Node Interfacial Tension15.9217 (dyne/cm)

First Node Pressure 150.00 (psig)First Node Temperature 128.66 (deg F)

Figure 7: Present VLP Matching IPR

From this point, the below table of System Solution Data can be determined prior to gas lift operation i.e. before injecting the Gaslift into the well.

Table 6: Present Wells System Capacity

Parameters Units

Liquid Rate STB/day 1795.4 Oil Rate STB/day 1526.1

Water Cut percent 15 Water Rate STB/day 269.3

Gas Rate MMscf/day 0.36168 Solution Node Pressure

psig 1000.51

In the subsequent analysis of Gas lift sensitivities after inject ion process, the changes in the above parameters; more specifically increase in oil rate and reduction in solution node pressure should be observed and discussed. These values which production engineers are more interested in, because the purpose of doing gas lift for any well is to deliver more quantity of oil and reducing the bottom-hole pressure to increase the drawdown pressure within the reservoir.

4.2. Gas Lift Sensitivities These sensitivities are adapted for specific application. For instance, the follow ing parameters can be modified are related with inflow of the well. Thus any alterations in these parameters will affect the IPR curve rather than VLP curve. - Reservoir Pressure and Reservoir Temperature - Productivity Index - Water Cut - Gas Oil Ratio (GOR), Water Oil Ration




- Dissolved and Free GLR On the other hand, the following parameters determine the outflow of any reservoir. For example, in the gas lift application; where the node is indicated at the bottom of the well, any changes or modifications in the below parameters can be considered while carrying out sensitivities. - Injection Depth - GRL Injected - Injection Depth - Total GOR - Gaslift Gas Injection Rate - Gaslift Gas Specific Gravity - Downhole Equipment, for example, Tubing/Pipe Diameter - Surface Equipment In this paper, injected GLR, injection depth and Gaslift Gas Injection Rate sensitivities are tempted to find out the effect of variation on the total oil production rate and bottom-hole flowing pressure (solution node pressure). In all steps, the node pressure, water cut and design operating pressure are considered as constant. Because Gaslift valves are already installed, thus no changes in valve position will be tried. Finally the purpose of these sensitivities is to output an overall gas lift design system for the well. This will include the trend of gas injection rate versus oil production rate and the position and number of gas lift valves.

4.2.1. Gaslift Gas Injection Rate Through using PROSPER simulator different injection rate of the lifting gas can be analysed. This can be done by selecting gas lift injection rate in the variable 1 of system 3 variables. For example, different injection rates are tried from 0 to 2.25 MM scf/day, consequently, the below graph is plotted:


0 0.5625 1.125 1.6875 2.25

1525.63

1730.58

1935.53

2140.48

2345.44

Sensitivity Plot (Well Number 1 13/06/2013 - 19:38:43)

Gasli ft Gas Injection Rate (MMscf/day)

Oil R

ate

(STB

/day

)








First Node Pressure 150.00 (psig)Bottom Measured Depth 3449.9 (feet)

Bottom True Vertical Depth 3449.9 (feet)


First Node 1 Xmas Tree 0(feet)Last Node 4 Casing 3449.9(feet)







Figure 8: Gaslift Gas Injection Rate Sensitivities

From this graph, it is clear that any injection rate more than 1.687 MMscf/day will not change the liquid rate (oil rate specifically) rather than increasing the pressure. By looking at the graph, the trend of the line is remaining constant when gas is injected at a rate higher than 2.25 MMscf/day, thus 1.75 MMscf/day is the maximum sensitivity of the well. However, this rate should be avoided, because only pressure will increase and probably more gas will be produced than liquid. Table (7) summarises the data of above graph, through which Optimum, maximum and Uneconomical injection rates are distinguished.

Table 7: Results of Injection Rate Sensitivities

Parameters

Gas Injection Rate (MM scf/day)

Optimum Maximum Uneconomical

0 0.25 0.5 0.75 1.0 1.250 1.500 1.750 2.000 2.250 Oil Rate (STB/day)

1526.1 2113.2 2241.6 2283.4 2308.9 2325.9 2336.7 2342.9 2345.4 2345.1

Sol. Node Press. (psig)

1000.51 921.16 903.04 897.07 893.43 891.01 889.47 888.59 888.22 888.27




4.2.2. Injected GLR In PROSPER simulator different injected GLR can be analysed. This can be done by selecting Injected GLR in the variable 1 of system 3 variables. For example, different GORs are tried from 237 scf/STB to 1200 scf/STB, consequently, the below graph is appeared:


237 477.75 718.5 959.25 1200

2266.31

2285.86

2305.42

2324.98

2344.54


GLR Injected (scf/STB)

Oil

Rat

e (S

TB/d

ay)


















Figure 9: Gaslift Gas Injection GLR Sensitivities

Table (8) summarises the data of above graph, through which Economical and uneconomical total GOR are indicated. By looking at figure (4.2), it is clear that when injected GLR > 400 scf/STB, the change in the oil rate is insignificant. Thus any further increasing in the injected GLR will have no impact pressure on the well and the situation is tending to be uneconomical.

Table 8: Results of Injection GLR Sensitivities

Parameters

Injected GLR (scf/STB)

Economical Uneconomical 237 344 451 558 665 772 879 986 1093 1200

Oil Rate (STB/day)

2869.9 2302.1 2324.0 2336.8 2343.1 2344.5 2342.3 2337.2 2329.7 2320.5

Sol. Node Press. (psig)

899.51 894.40 891.27 889.45 888.55 888.35 888.67 889.40 890.46 891.78

4.2.3. Injection Depth Sensitivity Various injection depths for the same injection gas can be analysed. This is done by selecting gas lift injection rate in variable 1 of system 3 variables and injection depth in variable 2. As shown in the figure below of injection sensitivities, the deeper injection of Gaslift gas rate leads to increase the oil rate/or liquid rate. This happens because, when gas injected at deeper point, this will result in further reduction in oil column density inside the vertical tubing. As a result of lightening the fluid, the hydrostatic pressure will reduce, hence the BHP. In the design consideration of any gas lift system; there is a limit of injection depth which is just above tubing shoe.





0 0.5625 1.125 1.6875 2.25

1514.07

1886.23

2258.39

2630.55

3002.71


Gasli ft Gas Injection Rate (MMscf/day)

Oil

Ra

te

(ST

B/d

ay)


















Injection Depth

(feet)

Curve 0 = 1985Curve 1 = 2550.5Curve 2 = 3116

0

0

0

00 0 0 0 0 0

1

1

1

11

1 1 1 1 1

2

2

2

2

22

Figure 10: Sensitivity Effect of Injection Depth on Oil Rate

Below table are the sensitivity results for the JAF well, to the same injection rate in MMscf/day, at three different injection depths of ft; consequently, the oil rate proportionally increased with increasing depth of injection.

Table 9: Injection Depth Sensitivity Result on the Well

Parameters

PROSPER

Calculated

Injection Sensitivity

Optimum

Injection

Sensitivity

Maximum

Injection

Sensitivity Injection Depth (ft) 1985 2250 3116

Gas Injection Rate (MM scf/day) 1.750 1.750 1.750 Oil Rate (bopd) 2390.2 2692.6 2999.9

Solution Node Pressure (psi) 881.84 837.34 790.18

5. CONCLUSION Before implementing gas lift optimisation, the average oil production rate (bbl/day) for this well was around 1700 (bbl/day), with relatively low drawdown pressure (psig) between average reservoir pressure and bottom-hole flowing pressure. Thus, to optimise the production, these wells are modelled in PROSPER program, through entering row field data of both reservoir fluids properties and well testing data for PVT matching and generating IPR and VLP for each well. The well is modelled in PROSPER step by step for VLP correlation comparison, Petroleum Expert-2 was found very close to well test data for all vertical/tubing performance. While for matching pipe correlation Beggs and Brill correlation is found the best fit correlation for production and flow line test. Design injection pressure is inputted based on the available source supply and considering bubble point pressure as well. The sensitivity results, through which maximum oil production rates are achieved as 2343 bbl/day at gas lift injection rate of l.75 MMscf/day. In addition, maximum and optimum GLR for the well is determined under fixed injection rate of 1.35 scf/day of GasLift gas rate based on the selected correlation for analysing injected GLR sensitivities and the result was; 451 scf/stb. And finally, an optimum injection depth for the fixed gas injection rate in MMscf/day for the well is obtained as 2250 ft.




6. REFERENCES 1. Ahmed, T., and McKinney, P. D. (2004). Advanced Reservoir Engineering. Oxford : Gulf Professional Publishing

is an imprint of Elsevier.

2. Beggs, H. D. (2003). Production Optimization Using Nodal Analysis. Oklahoma: OGCI and Petroskills

Publications.

3. Brown, K. E. (1984). The Technology of Artificial Methods (Vol. Volume 4). Tu lsa: PennWell Publishing

Company.

4. Economides, J. M., Hill, D. A., and Ehlig-Economides, C. (1994). Petroleum Production Systems. New Jersy:

Prentice Hall PTR.

5. GUO, B., LYONS, W. C., and GHALAMBOR, A. (2007). Petroleum Production Engineering. Elsevier Science

and Technology Books.

6. Hadiaman, F. (2011). GAS LIFT OPERATION, BEST PRACTICE, AND PERFORMANCE. WLS: Totalattitude.

7. Hall, J. W., and Decker, K. L. (1995). Gas-1ift Unloading and Operating Simulation as Appliedd to Mandrel

Spacing and Valve Design. SPE 29450, 63-78.

8. Lake, L. W. (2010). Petroleum Engineering Handbook (Vol. Volume IV). ZULIA, VENEZUELA: MERCADO

NEGRO.

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