11V6 pages Recommended Practice for Design of Continuous Flow Gas Lift Installations Using Injection Pressure Operated Valves API RECOMMENDED PRACTICE 11V6 SECOND EDITION, JULY 1999 REAFFIRMED, MARCH[.]
General
In designing a continuous flow gas lift installation, it is essential to evaluate the entire system For new installations, careful sizing and selection of all equipment is crucial, while for existing installations, it is important to assess the impact of the proposed design on the overall system.
Designing a gas lift string to function effectively under varying conditions is inherently challenging and requires numerous judgment calls from the designer While the proposed techniques aim to minimize these subjective decisions, complete elimination is not feasible It is advisable to utilize a graphical approach alongside supporting equations to better analyze and understand the impact of changing flow rates on valve design.
4.1.3 Continuous flow gas lift has advantages and limita- tions You are referred to API Gas Lift, Chapter 1 The follow- ing are brief discussions of the more important design considerations.
Well Performance (Inflow and Outflow)
The production of an oil well is categorized into two main types: inflow and outflow performance Inflow refers to the movement of produced fluids from the reservoir into the wellbore, while outflow pertains to the transfer of these fluids from reservoir depth to storage tanks Accurate predictions of both inflow and outflow conditions are essential for effective artificial lift design.
The inflow of a well is typically quantified by its productivity, particularly in the context of single-phase liquid flow This is represented by the productivity index (P.I = J), which can be formulated using specific engineering symbols.
Note: See Appendix A for symbol definitions.
In two-phase flow involving liquid and free gas, production does not exhibit a linear relationship with pressure changes This results in an inflowing performance relation curve when plotting flowing bottom hole pressure against the rate A useful approximation for this behavior, known as the Vogel IPR, applies to flow at pressures below the bubble point (assuming no skin effect) and can be expressed by the equation: \$$\frac{q_1}{q_a} = 1.0 - 0.2 \left(\frac{P_{wf}}{P_{ws}}\right) - 0.8 \left(\frac{P_{wf}}{P_{ws}}\right)^2\$$.
4.2.4 A more generalized approximation for multiphase flow of oil-water-gas for all conditions is as follows: a For flow above the bubble point:
Q l = (P ws – P wf ) x J b For flow below the bubble point:
By use of the above formulae, the flowing bottom hole pressure can be calculated for any possible production rate.
The outflow performance of a well is influenced by various interrelated factors, making accurate predictions challenging A reliable vertical multiphase flow correlation is crucial for effective gas lift design Numerous correlations exist, both published and proprietary; it is important to choose one that aligns well with the specific conditions of the well or field Conducting several flowing bottom hole pressure surveys is advisable to validate the selected correlation.
Vertical multiphase flow correlations are essential for developing gradient curves, which were historically the foundation for gas lift design before the advent of computer programs These correlations remain a widely accepted method for gas lift design today By applying an appropriate multiphase flow correlation, one can predict outflow under specific well conditions, allowing for the evaluation of various rates and gas-liquid ratios Additionally, tubing performance outflow curves can be generated and plotted against the inflow performance relationship graph, aiding in the determination of the expected rate when lifting from near the bottom, thus proving invaluable in gas lift design.
1Commonly used correlations: Poettmann and Carpenter; Hagedorn and Brown; Orikiszewski; Duns and Ros; Ros-Gray; MorelandMobil Shell Method; Beggs & Brill; Aziz et al.
R ECOMMENDED P RACTICE FOR D ESIGN OF C ONTINUOUS F LOW G AS L IFT I NSTALLATIONS U SING I NJECTION P RESSURE O PERATED V ALVES 3
Tubing or Annulus (Production Conduit) Flow Area/Size
The flow area is crucial in gas lift design, as a small conduit size can lead to increased friction loss and restrict flow rates, while an excessively large size may cause unstable flow and production issues, known as "heading." To avoid these problems, gas lift designers should consider adjusting tubing sizes to ensure flow rates remain within the stable flow region and minimize friction losses A total systems analysis approach is recommended for selecting the appropriate tubing size.
Facilities
Gas handling facilities, including compressors, meters, and pipelines, represent the largest portion of equipment costs in a gas lift system Additionally, this equipment typically incurs higher operating and maintenance expenses compared to other components of the system.
The design of API Gas Lift equipment is not covered in this recommended practice It is essential that surface facilities ensure a reliable and sufficient supply of dry, noncorrosive, and clean injection gas throughout the project's duration Additionally, the back pressure on producing wells due to pressure losses in surface production facilities should remain low, and the system must be equipped with effective control and measurement tools.
Gas Injection Pressure
Selecting the appropriate operating injection gas pressure is crucial for optimizing gas lift performance Typically, the injection pressure is determined by the gas sales system discharge pressure rather than efficiency Gas lift systems tend to be more effective and economical when the injection point is close to the producing formation Deep injection generally leads to increased production and reduced gas requirements Therefore, it is advisable to choose an injection gas pressure that allows for injection just above the producing zone whenever possible.
Kick-Off Injection Gas Pressure
The injection system can allow for a temporary increase in injection gas kick-off pressure Certain systems may utilize a high-pressure stage compressor or an external high-pressure source to facilitate well unloading or kick-off Typically, these systems operate within a defined pressure range, and opting for a higher than normal pressure may limit unloading to specific time frames.
Using a kick-off pressure to determine the depth of the first valve is a common and valuable practice, as it can enable deeper lift However, careful selection of this kick-off pressure is essential, as it will be necessary for future unloading scenarios.
Valves
4.7.1 The heart of the gas lift system is the gas lift valve.
(See API Gas Lift, Chapter 5.) In general, the designer should select a valve size, type, and design that will permit reliable, adequate single-point gas injection without frequent repairs.
In most cases, simple, unbalanced, injection pressure-oper- ated, nitrogen-charged bellows valves meet this requirement.
Valves are categorized into two types based on their operation: injection pressure operated and production pressure operated Injection pressure operated valves are activated by the pressure of the injection gas, while production pressure operated valves are controlled by the pressure of the flowing production at the valve's depth.
Continuous flow gas lift valves typically feature bellows, with the most common design incorporating nitrogen-charged bellows that make the valve opening pressure sensitive to temperature variations Alternatively, some valves utilize bellows without nitrogen closing force, relying instead on a spring, which minimizes the impact of temperature changes In high-pressure applications, it may be necessary to enhance the spring force with a dome charge to ensure sufficient closing force Consequently, temperature considerations are essential when determining the valve test rack set pressure, particularly for the portion of the opening force provided by the dome charge.
4.7.4 Different sizes and types of valves have specific load rates, which means that the stem will move off the seat an estimated distance for a specific opening pressure condition.
When selecting a valve for high gas injection rates, especially in high-rate wells, it's crucial to consider the valve's capacity to handle the required flow Some valves may become restricted under these conditions, so it's advisable to consult the manufacturer to ensure that a single valve can accommodate the necessary injection rate Additionally, it's generally recommended to choose the smallest valve port size that can still pass the required gas injection rate, as larger ported valves are more prone to unintended reopening, which can lead to multi-point gas lift injection due to a higher production effect factor.
4.7.5 Gas lift valves typically are available in three sizes;
Gas lift valves come in various sizes, including 5/8-in., 1-in., and 1 1/2-in The 5/8-in valves are only recommended when space constraints necessitate their use The 1-in valve is the most commonly utilized option, particularly in low-rate wells with 2 3/8-in tubing, and is compatible with both conventional and wire-line retrievable mandrels For higher rate wells with larger tubing, operators often prefer the 1 1/2-in valve due to its superior flow characteristics and lower production pressure effect factors Therefore, when larger port sizes exceeding 1/4-in are required for gas passage, the use of 1 1/2-in valves is advisable.
Characteristics of Unbalanced, Pressure Charged Valves
Pressure valves, which utilize a nitrogen dome charge for closing force, play a crucial role in continuous flow gas lift design Their opening and closing pressures are influenced by temperature, making it essential to consider the flowing temperature within the wellbore, which is typically higher than the static temperature at a given depth For optimal performance, relatively small ports are recommended to reduce the fluid gradient, while still allowing sufficient gas injection rates Additionally, the opening force of pressure valves is partially derived from production pressure, with larger port sizes enhancing this effect Consequently, increased production pressure can lead to unintended reopening of upper valves, potentially disrupting well operations Pressure valves primarily close when injection pressure decreases, necessitating that the surface operating injection pressure for deeper valves remains lower than that of the valves above to prevent interference and loss of lift energy.
This Recommended Practice focuses on unbalanced, pressure charged valves featuring ball stems and seats, which are the most widely utilized gas lift valves in the industry All gas lift manufacturers provide this type of valve, highlighting its prevalence and importance in gas lift applications.
Design Methods
4.9.1 There are a number of design methods, all of which have certain advantages or limitations Some are better suited for specific well conditions or for the type of valve chosen.
Most designs are similar with slight modifications on how or when safety factors are applied.
For injection pressure operated valves, the gas lift design is largely influenced by the injection gas pressure Accurate data reduces the necessity for safety factors When the gas injection pressure at the well is known under operating conditions, there is minimal need for arbitrary reductions However, gas lift systems often experience fluctuating pressures, and a measurable pressure drop occurs between the compressor and the well during flow Additionally, a pressure drop into the well is required for effective injection gas control.
An essential consideration in valve spacing is the producing pressure at the valve depth during the unloading process Utilizing an equilibrium curve allows for the prediction of operating producing pressures at different depths For more detailed information, refer to API Gas Lift, pages 72-73.
As the well is drilled deeper, both the rates and flowing pressures rise Relying solely on the equilibrium curve for spacing, without considering additional safety factors, can lead to well failure or multi-point issues This occurs because deeper lifts enhance production rates, subsequently increasing the overall output.
Flowing pressures can increase the opening force on upper valves, leading to multi-pointing or valve interference, where an upper valve opens unintentionally while producing from a lower target operating valve This phenomenon typically results in reduced production performance and increased gas consumption To predict the potential production rate, along with the required lift depth and injection gas pressure, it is advisable to utilize an equilibrium curve.
A variable gradient design, initially known as optiflow design, is another effective spacing method commonly utilized in production pressure-operated valves.
A high pseudo well head flowing pressure is calculated It is calculated by using the expected flowing pressure plus
The difference between the producing and injection pressure ranges from 20% to 25% A straight line is drawn to represent the expected flowing tubing pressure at the gas injection point or to a chosen pressure below the gas injection pressure at depth This line indicates a higher pressure than the operating production pressure, serving as a conservative spacing method.
Such a design gives closer valve spacing and normally requires more unloading valves but does not require a reduc- tion in gas injection pressure.
A recommended design method for injection pressure valves involves utilizing the maximum production rate gradient line for the producing pressure, while also decreasing the gas injection pressure by a specific amount for each deeper valve This amount is determined by a small nominal pressure drop plus a safety factor to account for data errors, valve settings, and variations in production pressure during unloading Implementing this pressure drop is essential to prevent the valves from multipointing, and it is crucial to increase the safety factor for valves with high production pressure effect factors (P PEF) The pressure drop can be calculated based on the minimum case.
Pressure Drop = P PEF x 100 psi + SF (optional) b For the maximum case:
Pressure Drop = 20 psi + [P PEF x 200 psi]
The pressure drop can be determined individually for each valve or applied uniformly across all valves of the same type and size Accurate data allows for the use of minimum pressure drops, while less reliable data suggests opting for higher pressure drops Additionally, if gas injection at the bottom is feasible, it is advisable to consider higher pressure drops.
Some designers opt to assess the pressure drop using a pseudo unloading pressure line, which is created by drawing a straight line from the valve's injection operating pressure to the flowing surface's producing pressure This line establishes the maximum producing pressure range (P max).
P min ) for the valve above (See Figure 16, Example Problem
An approach that leads to increased pressure drops in upper valves can significantly affect large ported valves, especially those with high production pressure effect factors The pressure drop in these instances can be calculated using a specific formula.
Pressure Drop = [P PEF – (P max – P min )] + SF (optional)
Temperature
Gas lift valves, particularly unbalanced pressure charged valves, operate by opening or closing at varying pressures influenced by temperature fluctuations To ensure proper functionality, it is essential to establish a standard reference temperature for valve settings, with most manufacturers commonly using 60°F as this benchmark.
Valve opening pressures on the design graph are determined based on downhole temperature conditions To ensure accurate valve settings in the workshop, these pressures must be converted to reflect the reference temperature The conversion factors for this temperature adjustment can be found in API Gas Lift, Table 4.1.
Table 1—Recommended Minimum Safety Factors for
2Other manufacturers use 80°F as the reference temperature One should check with the manufacturer to see which reference tempera- ture is being used.
900 psi opening pressure downhole at 130°F x
782 psi opening pressure in test rack at 60°F
As flow begins in the tubing string, the heat from the liquid mass is transferred upward However, only a portion of this heat can escape through the wellbore tubing to the shallower formations, resulting in a wellhead temperature that is higher than the typical surface temperature.
To accurately determine flowing temperatures, it is essential to conduct actual measurements at different production rates in the field Typically, temperatures rise significantly with increased production rates, higher water cuts, and greater velocities associated with smaller inner diameter tubing The chart presented in API Gas Lift, Figure 6.9, primarily reflects data from high water cut wells utilizing 2 1/2-inch nominal tubing; therefore, it should be used cautiously unless validated with field data.
Schmidt in their 1989 SPE 19702 paper, “Predicting Temper- ature Profiles in a Flowing Well,” may prove helpful.
When designing a continuous gas lift system, it is crucial not to rely solely on the static geothermal temperature gradient, as increased flow temperatures may cause the upper valves to remain closed, preventing proper unloading Upper valves should be engineered based on actual unloading rates and temperatures, with design temperatures exceeding the static temperature and the minimum flow rate, but remaining below the maximum anticipated flow rate A common practice involves creating a linear temperature profile from the surface flowing temperature at the expected maximum production rate to the reservoir temperature at depth This approach typically results in an unloading temperature line that is slightly lower than actual flowing temperatures, which can lead to the upper valves being locked closed during normal operations, making it a recommended strategy for most designs.
Flag Valve
In injection pressure operated valve designs, the bottom valve is typically set at a significantly lower pressure than the other valves to serve as a clear indicator of operation When the surface operating injection pressure falls below that of the upper valves, it suggests that the well is functioning from the bottom, provided that potential tubing leaks or other issues have been eliminated This indication is achieved by selecting various production pressure values, known as flag loads, for the bottom valve, emphasizing that there is no specific formula for determining the production pressure load for the flag valve.
To effectively set the flag valve at a lower surface operating pressure than the other valves in the string, several methods can be employed One approach is to select a minimum pressure by applying a gas gradient of 0.05 psi/ft in addition to the separator pressure Alternatively, an arbitrary minimum production pressure load, such as 100 psi or 200 psi, can be assumed Another option is to set the flag valve to open without any production pressure, allowing it to operate dry Lastly, a production pressure can be determined based on the minimum flow rate that the well is anticipated to produce, which is a commonly used method.
Some operators achieve the same thing by installing an ori- fice on bottom.
Gas Passage
Using the minimum port size that allows the desired gas flow rate can effectively reduce injection pressure drops between valves, thereby conserving lift energy Traditionally, gas passage calculations have utilized square-edged orifice nomographs, like those in API Gas Lift, Figure 4.8A, with subsequent adjustments for temperature and gravity Gas lift designers then modify the calculated gas passage in various ways, often assuming 100% gas passage as indicated by the nomograph or gas passage equations, and selecting a port or orifice that can accommodate this flow Empirical data supports the safety of this approach for small ported valves.
For optimal performance, utilize 3/16-inch or smaller ported 1-inch valves, or 1/4-inch or smaller ported 1 1/2-inch valves To determine the necessary port size for the design injection gas rate, refer to the nomograph, ensuring to account for 100% passage, and select a port one size larger for added safety Additionally, size the port by applying a 75% or 80% factor to the gas rate indicated by the square-edged orifice nomographs.
The successful practices for small port sizes and moderate to low gas injection rates highlight the need for accurate gas passage data in gas lift valves, especially with the introduction of large diameter, high rate completions Some manufacturers are currently gathering this essential data, which should be integrated into gas lift design to prevent issues with valve transfer caused by restricted gas passage.
Summary
This recommended practice provides guidelines for designing continuous flow gas lift installations that utilize injection pressure operated valves A successful design aims to optimize production by ensuring consistent single-point injection at the maximum allowable depth, which is determined by the gas injection facilities To achieve this maximum depth, it is essential to minimize pressure reduction between the valves during the well unloading process, while maintaining a necessary pressure reduction as a safety measure to prevent multi-point injection.
Graphical techniques play a crucial role in design by helping designers understand various design parameters This article presents three examples that illustrate the application of these techniques.
Good input data is crucial for creating an optimized design; without sufficient or accurate information, the design quality suffers This often leads to lower production rates, increased injection gas usage, and operational challenges Consequently, additional wireline operations may be required to pull and reset valves, or tubing may need to be removed to adjust the spacing of valves and mandrels.
Example Problem No 1: Design of Typical Well with Good Production Data
TYPICAL WELL WITH GOOD PRODUCTION
5.1.1.1 A gas lift design problem which commonly occurs is the case for a well that has been completed and produced but now requires a gas lift design and equipment installation.
In situations where the current gas lift design is inadequate or when tubing is removed for repairs, it becomes necessary to reassess and modify the gas lift system Several effective production tests have been conducted in these scenarios This example will illustrate the optimal spacing of valves and mandrels to achieve maximum production rates while utilizing a limited amount of injection gas The design aims to facilitate gas lifting from the producing zone or as deep as possible, employing injection pressure-operated valves for efficient unloading.
5.1.2.1 A summary of the well data are given in Figure 3,
The Gas Lift Well Data Sheet details a well drilled to a depth of 8,100 feet, completed as a single producer with 7-inch casing and 2 7/8-inch tubing The producing interval spans from 8,000 to 8,025 feet within a sandstone formation Existing equipment will be removed and can be replaced if needed The flow line consists of 3-inch line pipe, and the central facilities are located just 500 feet from the well, with no issues related to high back pressure.
The well is part of a limited water drive reservoir that was initially hydropressured with a bubble point pressure of approximately 2445 psig Although the reservoir pressure has decreased to around 2150 psig, it has stabilized over the past two years Recent pressure surveys indicated a static pressure of 2125 psig with no measurable skin During a pressure buildup test, the well produced 100 barrels of oil per day (BOPD) and 100 barrels of water per day (BWPD), with a flowing bottom hole pressure of 1941 psig and a flowing wellhead pressure of 100 psig The oil gravity was recorded at 35° API, and the gas-oil ratio remained close to its original value of 700:1 standard cubic feet (SCF) of gas per stock tank barrel of oil The well has since loaded up and ceased production, with conditions expected to remain stable in the coming years.
5.1.3.1 The field currently has a gas lift system installed that provides 1250 psig dehydrated sweet injection gas.
The well's pressure was recorded at 1200 psig, with a maximum lift capacity of 750 MCFD, although a preferable rate is below 700 MCFD Additionally, the specific gravity of the injection gas is 0.65.
The gas lift design aims to optimize the well's production near its maximum capacity by assessing the well's inflow capability and aligning it with the outflow conditions Given that the well generates free gas in the reservoir beneath the bubble point, the Vogel correlation was applied to calculate the inflow rates and flowing pressures.
5.1.5.1 The Hagedorn and Brown gradient curves were selected for determining outflow performance These curves are widely used and in many fields are adequate for gas lift design.
The well is fitted with 2.5-inch nominal tubing, which is optimal for its inflow characteristics This tubing size is ideal for production rates between 500 and 1500 barrels per day (BPD) By utilizing the gradient curves from Appendix B and assuming a flowing well head pressure of 100 psig, the required flowing bottom hole pressures were calculated for various gas-to-liquid ratios (GLRs).
* 2 Lease name and well no.: _
* 4 Casing: in OD; _ #/ft; _ Grade; _ ft
5 Liner: _ in OD; _ #/ft; _ Grade; _ ft
6 Open hole: (yes/no) _ Gravel pack (yes/no)
* 7 Well depth (TVD/MD): _ ft Plug back TVD: _ ft
* 8 Perf Interval _ - ft Reference depth: ft
* 10 TBG LNG ft; OD in.; WT lb/ft; Grade _ THD
11 SSSV: mfg & type _ ; Depth ft; Bore in.
12 Wellhead mfg & type _; (Bore ID) ; WP psi
13 Choke: mfg & type ; Size max ID / 64 in.
14 Flowline: size ID in.; Length: ft
15 Well profile: (TVD/MD or deg)
B Reservoir, Test and Production Data
* 16 Last test: (q o ) = BOPD (q w ) = _ BWPD (q g ) = _ MSCFD
* 17 Water cut Formation R go : _ R gl :
* 18 Flowing WHP (P wh ) psig; Separator pressure (P sp ) psig
* 19 Static BH pressure (P ws ): _ psig @ _ft
20 Static fluid level Pressure psig gradient _ psi/ft
* 21 Flow BHP (P wf ): psig @ ft @ rate BLPD
* 22 Oil API gravity _ Water specific gravity _
* 24 BH Temp (T f ): _ @ Surf temp (T s ): Flow temp (T wh ): _
* 25 Bubble point (PB): psig; PI (J): _ BPD/psi; flow eff _
26 Sand (yes/no) _; Paraffin (yes/no) _; Scale (yes/no)
27 H 2 S (yes/no) _; CO 2 (yes/no) _; Emulsion(yes/no) _
* 29 Tubing/flow _ New installation/rerun/modification
* 30 Production rate (q 1 ): min max _ design _
* 31 Max water cut %; Max lift depth ft; Min BHP psig
* 32 Comp inj gas pres (p g ): _ psig: Well inj pres _ psig
33 Header/sales inj pres _ psig; Max (K o ) inj pres _ psig
* 34 Inj gas temp @ well °F; Inj gas SG (SG i ) _
* 35 Inj gas volume: max/unloading/design _ MSCFD
* 36 Load fluid grad (g s ): psi/ft lower flow grad psi/ft
* 37 Min spacing ft; Min inj decrease _ psi; Design diff psi
* 38 Design flow press (P wh ) psig Design flow temp (T wh )
39 Gas lift valve: mfg & type ; port _ in.; A p /A b _
*Indicates data that must be supplied for good design.
A comparison of outflow pressures with the well's inflow pressures reveals that production rates of 900 BFPD or higher are not achievable, while rates between 200 and 800 BFPD are feasible For a stabilized production rate, the inflow performance pressure must match the required outflow performance pressure, as illustrated in Figure 4.
The intersection of the inflow performance relationship (IPR) curve and the tubing performance curve indicates the predicted production rate for the well In this case, the maximum achievable production rate is approximately 800 barrels of fluid per day (BFPD).
A comparison of tubing performance curves for different gas-liquid ratios (R gl) is essential for selecting the optimal injection gas An R gl of 800 limits production to under 800 BFPD While increasing the R gl can enhance the production rate, the incremental increase in production per MCF diminishes steadily.
5.1.6.2 For a total R gl of 1500 and a producing R gl , of 350, a production rate of 800 BFPD would need:
(1500 – 350) x 800/1000 = 920 MCFD injection gas whereas for a 1200 R gl , 680 MCFD is required, for a 1000 R gl , 520 MCFD is required, and for a 800 R gl , 360 MCFD is required.
The design will be based on a producing R gl of 1200 due to the limited amount of injection gas available in the field It is advisable to conduct a further evaluation after installation, relying on actual well tests Additionally, as water cut increases in the future, there may be a need for slightly more gas.
5.1.7.1 The temperature of the injection gas and pro- duced liquids have a significant effect on the gas lift
Figure 4—Oil IPR Graph design—especially when using nitrogen charged bellows valves Actual temperature measurements are recommended at different production rates.
5.1.7.2 In this well the formation temperature of the reser- voir (bottom hole temperature) is 178°F, the surface static temperature is 78°F, and the flowing wellhead temperature at
200 BFPD was measured to be 86°F The well flows up 2.5- in nominal tubing The geothermal gradient is found to be
5.1.7.3 The flowing temperature at 800 BFPD is deter- mined as follows:
The well will not reach its maximum production rate until injection starts at the deepest point, necessitating the closure of the upper valves at reduced rates and consequently at lower temperatures.
5.1.7.5 As the well lifts deeper, the higher flowing temper- atures will help keep the upper valves closed.
5.1.7.6 Average injection gas temperature = (78 + 178)/2 128°F (The flowing fluids have only a small effect on the injection gas temperature.)
As depth increases, the available injection gas pressure rises due to the weight of the gas, particularly when larger injection tubulars are utilized In this well, the surface gas injection pressure is expected to reach a maximum of 1200 psig, with operating pressures around 1100 psig The pressure increase per 1000 feet can be estimated using the provided figure.
For a gas with a specific gravity of 0.65, the pressure increases approximately 30 psi for every thousand feet at a surface pressure of 1100 psig, and about 32.5 psi per thousand feet at a surface pressure of 1200 psig Therefore, a conservative estimate of 30 psi per thousand feet will be utilized in this analysis.
5.1.9.1 There are many methods for spacing valves This design will use a graphical (pressure-depth) approach but will also provide supporting calculations Ample safety factors
Average Pressure Increase (psi/1000 ft)
Based on P gd = P g x e (0.01875 x SG i x D w )/(T av x Z)
Figure 5—Weight of Injection Gas Column will be used to ensure unloading The following are the given pressure and depth data that need to be initially plotted:
P wh = Pressure at the wellhead = 100 psig.
P g = Pressure of injection gas at well = 1200 psig.
T wh = Flowing temperature at wellhead = 108°F. g s = Static gradient of load fluid in annulus = 0.465 psi/ft. g g = Gas gradient = 30 psi/1000 ft or 0.03 psi/ft.
P gd = Pressure of injection gas at well depth 1440 psig.
T f = Formation temperature = 178°F. f w = Water cut fraction = 0.50.
To effectively space the valves, it is essential to predict the tubing flowing pressure While several methods have proven successful, utilizing the gradient curve based on the expected maximum production rate is one of the most effective approaches In this scenario, the anticipated production rate is 800 BFPD with a gas-to-liquid ratio (GLR) of
1200/1 through 2.5-in nominal tubing The following depth and pressure values were read off the appropriate graph in
These values are then plotted on the design graph (see Fig- ure 6)
Note: If the design graph has the same scale as the flowing gradient curves in Appendix B, the curve may be traced.
During unloading operations, it is crucial for the gas injection pressure to be slightly higher than the tubing pressure when the valve is uncovered; otherwise, gas injection will not occur, halting deeper unloading Additionally, to ensure the closure of upper injection pressure-operated valves, the casing pressure must be reduced; failing to do so may lead to uncertain deeper lift and increased gas requirements A pressure drop (PD) of 25 psi in gas injection pressure is deemed reasonable for effective valve operation For instance, with a valve having a P PEF of 0.1 and applying a conservative safety factor of 15 psi, the pressure drop can be calculated as PD = 0.1 x.
100 + 15 = 25 psi This 25 psi drop is slightly higher than the
10 psi minimum, and is less than the 40 psi maximum recom- mended as discussed in 4.9.
Example Problem No 2: Design of a Well with Little or No Production Data 17
In many cases, a gas lift design is necessary when detailed production information is scarce, such as in newly drilled wells, wells worked over to previously unproduced sands, or when current producing wells lack sufficient data This situation necessitates the creation of a gas lift design capable of functioning across a broad spectrum of production conditions While it is possible to develop an adequate design, the trade-off often involves higher equipment costs due to the need for more resources than would be required with better well data Similar design techniques can be applied when some well data is available, but a single design must accommodate a wide range of flow rates due to multiple through-tubing recompletions in zones with varying production characteristics.
This section focuses on tubing flow, where "production pressure" specifically refers to the pressure within the tubing, while "injection gas pressure" or "injection pressure" pertains to the pressure of the injection gas in the tubing-casing annulus.
5.2.2 Selecting the Design Flow Rate(s)
When designing a well with little or no production information, flow rates can be estimated by analyzing data from similar wells in the same reservoir or using analog data In situations where multiple recompletions occur within the same wellbore, the design must account for a known range of flow rates For wildcat wells or workovers to previously unproduced zones, the designer must establish minimum and maximum anticipated flow rates based on available data Consequently, the spacing and valve settings should be designed to accommodate any flow rate within this range, noting that a wider range of flow rates will necessitate more valves.
The target gas-liquid ratio (R gl) curve for designing flow rates is determined by the total gas rate available for well lifting, ensuring it does not exceed the minimum gradient The minimum gradient represents the R gl level beyond which additional gas injection fails to further lighten the lifted fluid For instance, with an expected liquid flow rate of 400 BFPD and a maximum lift gas rate of 400 MSCF/D, the gas-liquid ratio curve is established for design considerations.
1000/1, provided this ratio is less than the minimum gradient
When designing for gas transfer and valve sizing, it's essential to reference various R gl curves corresponding to the design flow rate The minimum gradient is directly related to depth, as illustrated in Figure 10, where the minimum gradient for depth 1 is 800/1 and for depth 4 is 1500/1 The absolute minimum gradient for maximum depth is 1500/1, but for depths shallower than 4, the practical minimum gradient will be lower than this absolute value Utilizing gas-liquid ratios that exceed the practical minimum gradient for your design lift depth can lead to inefficiencies and counterproductive outcomes.
Designing injection pressure-operated valves for varying flow rates presents a significant challenge due to temperature fluctuations The flowing temperature in the wellbore depends on the flow rate, which remains an unknown variable If the flow rate is set too low, it can lead to higher-than-design temperatures, potentially causing the valves to lock out and preventing them from opening.
Elevated temperatures beyond design specifications raise the dome pressure in nitrogen-charged pressure valves When a well operates at a flow rate lower than the design, the temperature gradient decreases, resulting in lower valve opening pressures and the potential for valve interference.
When selecting the flowing surface temperature for various flowrate designs, several strategies can be employed First, one can make an initial estimate based on the expected flow rate and be ready to adjust the valves once production data is available Alternatively, if the anticipated flow rates are relatively close, an average flowing surface temperature can be assumed, such as using 600 BFPD for a range of 400 to 800 BFPD In cases where there is a significant difference between potential flow rates, it may be necessary to set the flowing surface temperature higher than the average to avoid valve lock-out, for instance, using 700 or 800 BFPD for a range of 200 to 1000 BFPD.
BFPD for flowing temperature estimate)
When a well is put into production, there is a risk of needing to pull and reset the valves based on actual data, particularly as the reliability of the design information diminishes.
Using retrievable equipment, particularly retrievable valves, is essential in high workover cost areas and when designing wells for varying flow rates This approach provides the flexibility to pull and reset valves for optimal performance based on production data, helping to prevent significant issues, provided that the spacing between valves is appropriately designed for the intended flow rates.
The sizing of gas lift valve ports must accommodate the desired gas flow rate as determined by the Gas-Liquid Ratio (R gl) curve To establish the total required injection gas rate, multiply the total fluid rate in barrels of fluid per day (BFPD) by the appropriate factors.
In the design method outlined, it is crucial to consider that the pressure drops between valves are greatly influenced by the chosen port size To optimize lift energy and minimize pressure drops, especially when operating injection pressure is constrained, it is advisable to select the smallest port that can accommodate the necessary gas flow rate This approach also reduces the risk of unintentional gas overinjection.
To prevent valve interference, it is essential to manage the injection pressure drops between deeper valves A common method is to configure each deeper valve to open at the closing pressure of the valve above it; however, this can lead to significant losses in operating injection pressure Choosing excessively low injection pressure drops, such as 5, exacerbates this issue.
A minimum gradient of 1500/1 psi and 10 psi can lead to an increased likelihood of valve interference, particularly influenced by the size of the port being utilized Additionally, choosing excessively large injection pressure drops may exacerbate this issue.
50 psi, or higher, will result in loss of lift energy and may cause operation much higher up the hole than would other- wise be necessary.
This method provides a logical approach to selecting injection pressure drops that balances two extremes while considering port size Larger ported valves, which have high production pressure effect factors, are more prone to valve interference and necessitate greater injection pressure drops compared to smaller ported valves The reasoning for this pressure drop calculation method will be elaborated in the following paragraphs.