Design, Operation, and Troubleshooting of Dual Gas lift Wells API RECOMMENDED PRACTICE 19G9 SECOND EDITION, APRIL 2015 Special Notes API publications necessarily address problems of a general nature W[.]
Terms and Definitions
For the purposes of this document, the following terms and definitions apply
A comprehensive system for monitoring and optimizing gas-lift operations involves measuring key parameters, controlling the gas-lift injection rate, diagnosing issues, and enhancing overall performance.
Normally measured at the midpoint of the perforated interval
A process where fluids from different productive formations are combined and produced through a single conduit
The flow of reservoir fluids from one productive formation into another
Wells that include two production tubing strings designed to produce from two separate reservoirs, using gas-lift
Operating conditions from the moment the field is opened to production until it is closed and abandoned
The prevailing gas, oil, and water geometrical distribution when flowing through a pipe
Common flow regimes for gas-liquid mixtures such as bubble flow, dispersed bubble flow, plug flow, slug flow, froth flow, mist flow, churn flow, and annular flow
Measured at the midpoint of the perforations when the well is off production
The ratio of produced gas to produced oil
Ice-like crystalline compounds formed by water and natural gas molecules at high pressures and low temperatures
The ability of fluid to flow from the reservoir into the wellbore as a function of pressure differential from the reservoir to the wellbore
A curved relationship in barrels per day per psi drawdown
An evaluation of the lift gas flow used to evaluate well performance
A type of gas-lift valve used when the injection (casing) pressure is the primary opening pressure
Well completions where data recording and well control can be perform remotely
A form of gas-lift where slugs of gas are injected intermittently beneath slugs of liquid
Restoring a well to production after a period of inactivity involves addressing the potential presence of fluid in the annulus, which may need to be unloaded The necessity of this process depends on whether there is a leak in the tubing.
Well completions that have more than one wellbore branch radiating from the main borehole
The situation where gas-lift injection gas enters the production stream from more than one position in the tubing string
Adjustments to lift gas and well flows to achieve the maximum return without causing formation or system damage
A situation where the tubing pressure is fluctuating by more than a defined amount in a defined period of time
A type of gas-lift valve used when the production (tubing) pressure is the primary opening pressure
The straight-line method for defining inflow performance quantifies production in relation to pressure drop from the formation to the wellbore, measured in barrels per day per psi drawdown.
Test rack opening pressure, measured in the test rack when the tubing pressure is atmospheric pressure
Measured at the midpoint of the perforations when the well is off production
2.1.27 supervisory control and data acquisition
Real-time data captured by a supervisory control and data acquisition system
Monitoring gas-lift operations to determine performance and to detect and address problems
A commonly accepted equation used to predict the rate of gas passage through a given orifice size
The process of displacing initial annular and/or tubing fluids in the well when gas-lift injection gas is started
A plot of pressure vs depth in a flowing or gas-lift well.
Acronyms and Abbreviations
GOR gas to oil ratio
SCADA supervisory control and data acquisition
General
Dual wells exist for a number of reasons; the primary ones are summarized in this section.
More Efficient Drilling
Drilling a single wellbore to access multiple vertically oriented production zones is often more appealing than drilling separate wells for each zone In certain fields, multiple reservoirs can be stacked vertically, with some containing as many as 5, 10, or more distinct reservoirs The development plans for these complex fields necessitate thorough study and analysis.
The primary goal is to efficiently extract reserves while ensuring environmental protection and responsible global citizenship It is advisable to avoid multiple completions that could lead to significant reserve loss or delayed production Although it may seem appealing to drill a single well to access multiple reservoirs simultaneously for faster production, this must be executed properly to realize the intended benefits A common question arises: "Is it possible to produce multiple zones from a single completion without resorting to dual completions?" To determine the optimal development strategy for multiple zone reservoirs, a thorough analysis of various options is essential.
Dual Gas-lift Alternatives
In some cases, there may be reasonable alternatives to dual gas-lift These should be considered, recognizing the expertise necessary to effectively operate dual gas-lift wells
3.3.2 Alternating Production from the Two Zones
In the past, well production rates were regulated, allowing for rapid extraction of a well's monthly limit Operators could produce from one side of a dual well while closing the other, a practice that is now uncommon However, it is still feasible to enhance overall production by alternating between the two sides of a dual well This document focuses on the criteria that enable simultaneous production from both zones, which can lead to increased output.
3.3.3 Gas-lifting One Side, Gas Assisting the Other
In some cases, one zone should be gas-lifted full time while the other zone will flow once it has been started
To initiate the "flowing" zone, gas can be utilized if it becomes loaded; however, once production starts, it can sustain flow independently It may be required to temporarily shut in the side typically using gas-lift, as adjusting the pressures on the gas-lift valves for both sides of the well may also be necessary.
3.3.4 Gas-lifting One Side, Naturally Flowing the Other
In a dual gas-lift system, it is feasible to flow one side while gas-lifting the other; however, this does not constitute true dual gas-lift When executed properly, the flowing well should not disrupt the single-string gas-lift operation on the opposite side A potential challenge arises from restrictions in tubular size, which stem from the requirement of accommodating two tubing strings within a single casing.
3.3.5 Gas-lifting One Side, Pumping the Other Side
Pumping one side of a dual while gas-lifting the other is an uncommon practice, primarily because it requires pumping the active side below a packer This setup compels any gas produced from that zone to pass through the pump, but most pumps struggle to operate effectively in gas-laden environments Therefore, this approach should only be contemplated in the most exceptional circumstances.
General
This section aims to outline the recommended and non-recommended dual gas-lift practices, as well as to provide guidance on which practices should be adopted and which should be avoided (refer to Annex D for further details).
This section contains a summary of the practices that are specified in detail in the following sections of this document.
Practices That Are Recommended
The following dual gas-lift practices are grouped into categories for easy reference Each recommended practice is supported by additional information in this document
The following should be performed when selecting wells for dual gas-lift:
— carefully evaluate all of the factors and only select wells for dual completion where the factors favor dual operation,
To ensure optimal performance, it is crucial to assess all potential operational challenges before selecting wells for dual completion This selection should focus on wells that are likely to experience extended pre-gas-lift operations and those with a high probability of successful dual gas-lift operations.
Defining Unacceptable Wells
Avoid attempting dual gas-lift if the casing is too small or the zones are too far apart See A.3 for additional information on candidate well selection criteria.
Considering Alternatives to Dual Gas-lift
The following are issues to consider regarding alternatives to dual gas-lift:
— consider commingling the two zones if this is feasible and allowed,
— consider developing the two zones as single completions if production will be important and it would be practically feasible to do so,
— consider alternatives if dual gas-lift expertise is not available.
Dual Gas-lift Well Design Issues
For optimal gas-lift performance, it is advisable to install mandrels a few tubing joints above the dual production packer, ensuring a conservative spacing design Mandrels should be positioned closely enough to facilitate unloading and effective operation, irrespective of the gas-lift valve type Additionally, they must be arranged to achieve optimal lifting depth in both zones, taking into account the well's reservoir pressure and productivity It is essential to maintain the same number of mandrels in both zones, with the upper zone mandrels spaced one tubing joint above those in the lower zone.
4.5.2 When One Zone Is Much Deeper
For effective gas injection beneath the dual zone production packer, utilize an insert string in the long side of the dual if the tubing diameter permits If the tubing is insufficiently sized for an insert string, limit mandrel designs to the depth of the upper production packer It is advisable to avoid complex designs due to the heightened mechanical risks they pose.
4.5.3 PPO vs Injection Pressure Operated (IPO) Debate
For effective unloading, utilize IPO gas-lift valves when the expected depth of lift is known In cases where the depth is uncertain and unloading valves may be required, opt for PPO gas-lift valves Special gas-lift valves, such as balanced IPO valves, should only be employed in unique situations where standard IPO or PPO valves are impractical.
See Annex C for a recommended unloading design for PPO gas-lift valves
4.5.5 Operating Valve or Orifice Valves
When the depth of lift is uncertain, ensure the well is designed to function with an unloading valve if needed If the depth of lift can be determined and flexibility in the injection rate is required, opt for a design that utilizes an orifice Conversely, when both the depth of lift and the desired injection rate are known, and stability is a priority, the design should incorporate a nozzle venturi orifice.
4.5.6 Where Mandrels Are Too Far Apart
When upper mandrels are too widely spaced to effectively utilize PPO, balanced IPO, or differential gas-lift valves, it is advisable to implement IPO valves in the upper mandrels until the well reaches a suitable operating depth At that point, PPO valves can be employed, or alternatively, a standard orifice or nozzle venturi orifice can be used if the deepest mandrel has been attained For further guidance on designing dual gas-lift systems with widely spaced mandrels, refer to sections 4.7.2, 5.6, 5.7, 5.10, and 6.5.
When choosing gas-lift valves for dual gas-lift systems, various alternatives are available, and no single method is universally endorsed It is advisable to consult with experienced operators to explore the most effective strategies they have utilized For additional insights on selecting gas-lift valves, refer to section A.6.
Dual Gas-lift Operations
For optimal results in dual gas-lift well installations, it is advisable to install both strings simultaneously; however, if they must be run separately, prioritize the long string first Ensure that an expert from the packer supply company is present during the installation and testing of the packers on the long string, as well as when setting the short string into the dual packer Additionally, if surface-controlled gas-lift valves are being used, have a specialist from the surface control company on-site for installation When installing chemical injection lines, adhere to the same procedures as for electrical cables or hydraulic lines, and conduct pressure tests on each packer to meet the recommended pressure standards.
Cross-flow in a dual gas-lift well can happen when pressure differences exist, allowing fluid to move from a higher pressure zone to a lower pressure zone, especially when dummies or valves are removed from the higher pressure tubing string To mitigate this issue, it is essential to set tubing plugs as necessary For additional details on wireline operations, refer to sections 5.10, 6.3, 6.4, 7.2, 7.3, 7.4, 8.3, and A.15.
Before conducting wireline operations on dual gas-lift wells, it is essential to perform pressure integrity tests on the casing, tubing, and packer In the event of any issues, refer to the troubleshooting chart in Table 1 for assistance in diagnosing and resolving the problems.
To ensure optimal performance, it is advisable to unload the casing annulus using the long string, as it typically contains the deeper gas-lift mandrels Adhere to the unloading procedures specified in section 5.2 for best results.
To effectively restart both sides of a dual system after a period of inactivity, begin with the optimal zone to establish stability before initiating the second zone To prevent the first zone from "robbing" gas during the ramp-up of the second zone, consider installing chokes in the unloading valves if IPO gas-lift valves are utilized When restarting one side of the dual, apply the same procedure as used for the second zone during the initial restart For additional details on the kick-off process, refer to sections 6.6.2 and D.1.
To maintain optimal production, it is essential to keep both zones operational without interruption Continuous gas injection at the desired depth in both zones is crucial, particularly during well tests and pressure surveys Implementing an automatic control system can help ensure stable gas delivery at the required rate and pressure, even during gas-lift system disturbances For further details on managing dual gas-lift wells, refer to Section 6.
To optimize the injection rate for each side of a dual gas-lift well, follow the procedures outlined in section 6.8 or conduct a multirate well test Establish the allowable range of injection rates surrounding the optimum value, identifying both minimum and maximum limits Finally, create a control strategy to effectively distribute gas to each dual well, ensuring that the injection rates remain within the defined acceptable range for both sides.
Poor Candidates for Dual Gas-lift
Certain characteristics or well conditions can hinder the effective operation of dual gas-lift systems Many of these challenges are the opposite of the conditions that typically qualify a well as a suitable candidate for dual gas-lift.
4.7.2 Two Zones Too Far Apart
When the vertical distance between two zones exceeds 305 m (1000 ft), implementing dual gas-lift can become challenging In such cases, gas-lift gas for the deeper zone must be injected above the production packer of the shallow zone, potentially rendering the gas-lift for the lower zone ineffective Additionally, significant separation between the zones often leads to varying reservoir pressures, which can result in differing operational requirements for gas-lift systems.
4.7.3 Low Formation Gas to Oil Ratio
Low gas to oil ratios (GOR) in one or both zones can complicate gas-lifting, as all necessary gas for production must be injected This challenge is especially pronounced when the deeper zone exhibits a low GOR For effective production, the lower zone's output must flow from its perforations to the gas-lift injection depth, which is situated above the shallow zone's production packer.
4.7.4 Intermittent Operation of One or Both Sides
When reservoir pressure decreases or inflow performance declines, maintaining effective continuous gas-lift can become challenging In such cases, intermittent gas-lift may prove to be a more efficient solution This method involves injecting gas into the tubing in cycles, leading to notable fluctuations in injection pressure However, it is often impractical to apply intermittent gas-lift on one side of a dual gas-lift well while simultaneously using continuous gas-lift on the other side.
For effective dual gas-lift systems, the minimum casing size required is 17.78 cm (7 in.), which allows for the installation of gas-lift mandrels compatible with 2.54 cm (1 in.) gas-lift valves.
Considering Artificial Lift Alternatives to Dual Gas-lift
Completing wells as single producers with a dedicated wellbore for each reservoir eliminates the complications linked to dual gas-lift systems Achieving this necessitates a thorough analysis that evaluates various factors, including drilling, development, operational efficiency, and workover challenges.
Completing dual wells is more complex than single wells due to the additional tubing, packer, and gas-lift equipment, making the process more challenging This increased complexity also raises the risks and difficulties associated with workovers Furthermore, abandoning a dual well is more complicated because of the extra equipment and the necessity to seal two zones.
Effective dual gas-lift operations demand specialized knowledge, experience, and expertise, making it unsuitable for untrained or inexperienced personnel If a company lacks qualified individuals and cannot source them from reliable service or consulting firms, it is advisable to refrain from engaging in dual gas-lift activities.
Commingling production from multiple reservoirs within a single wellbore can be advantageous if it is technically feasible and permissible, especially when there are reliable methods to measure or estimate the output from each zone, as this approach may be more efficient than implementing dual gas-lift operations.
Performing remedial work in the upper zone below the tubing can be challenging due to the presence of deeper zone tubing This situation complicates the use of dual gas-lift systems and poses risks to the integrity of both the long side and the entire well.
4.8.6 Using Casing Pressure for Surveillance
Casing (injection) pressure is a crucial variable for monitoring gas-lift operations, as it indicates which gas-lift valve is open, the location of gas injection in the tubing, and the stability of the well In single gas-lift systems, this pressure helps identify the type and causes of any instability However, in dual well systems, the shared casing pressure complicates surveillance and diagnostics, making it more challenging to assess the performance and stability of each side.
5 Dual Gas-lift Well Designs
General
The purpose of this section is to put many misconceptions to rest and offer RPs that, if followed, can help lead to successful dual gas-lift system designs.
Mandrel Spacing
Correct mandrel spacing is crucial in dual gas-lift design, as it enables the well to unload to the desired operating depth This spacing is vital, especially when operating from an upper gas-lift mandrel depth The primary requirement is to ensure the well can unload effectively and reach the intended operating depth In a dual gas-lift well, only one annulus needs unloading, and the key design principle is to incorporate sufficient mandrels to facilitate the unloading and operation of both zones at their respective depths.
5.2.2 Spacing Based on Requirements of the Lower Zone
In the design of mandrel spacing for unloading in dual gas-lift wells, it is common to base the configuration on the requirements of the deepest zone This strategy ensures that the completion fluid is effectively removed to the bottom operating mandrel depth of the long string Consequently, mandrels are positioned according to the needs of the deeper string, while those for the shorter string are typically placed one tubing joint above the long string mandrels to prevent overlap at the same depths.
5.2.3 Basing the Design Spacing on the Most Prolific Zone
Basing mandrel spacing on the most productive zone ensures that mandrels are positioned closer together and higher in the well, which is crucial for optimizing lift from the ideal depth of a high-yield well To account for potential discrepancies in productivity, it is advisable to install mandrels down to the depth of the upper zone's production packer, a practice known as "bracketing." Typically, lower mandrels are spaced between 91.4 m and 152.4 m (300 ft to 500 ft) apart, with the short string mandrels positioned one tubing joint above those in the long string.
5.2.4 Design Spacing Based on Conditions/Needs
Designing mandrel spacing for each side according to individual requirements can be problematic, as the specific needs of each zone may be unknown during the design process Therefore, it is generally not advisable to attempt a tailored mandrel spacing for each zone Additionally, it is crucial to ensure that no two mandrels are positioned at the same depth.
5.2.5 Design with Flexibility to Use Different Types of Valves
When designing mandrel spacing for gas-lift systems, the specific type of gas-lift valve may not be known in advance Consequently, it is essential to adopt a conservative design approach that accommodates the gas-lift valve requiring the closest spacing.
5.2.5.2 Effect of Different Types of Gas-lift Valves
This section outlines the various types of gas-lift valves suitable for dual gas-lift applications, highlighting their distinct requirements and the necessity for specific mandrel spacing to meet these needs.
PPO gas-lift valves are primarily controlled by tubing (production) pressure, and theoretically, they can be designed to operate with the same surface casing (injection) pressure This allows for slightly wider mandrel spacing compared to IPO gas-lift valves when using the same tubing pressure design line However, in practice, a higher tubing pressure design line is typically employed, resulting in mandrels for PPO usage being positioned closer together than those for IPO usage Additionally, since PPO valves can be utilized on one or both sides of a dual, the mandrel spacing must be sufficiently close to meet this requirement.
The operation of IPO gas-lift valves is mainly influenced by the casing pressure, which must be reduced for upper unloading valves to close properly This necessitates closer spacing of mandrels compared to designs without this pressure drop requirement However, the tubing pressure design line for IPO valves is typically positioned lower than that for PPO valves, resulting in wider mandrel spacing for IPO designs Additionally, since IPO valves can be utilized on either side of a dual system, mandrel spacing should be sufficiently close to accommodate their use alongside different valve types.
5.2.5.2.4 Balanced IPO Gas-lift Valves
Balanced IPO valves primarily rely on casing (injection) pressure for their opening force, exhibiting a significant tubing effect of around 25% Due to their heightened sensitivity to variations in tubing (production) pressure, these valves can serve as an alternative to PPO valves, particularly in scenarios where the mandrel spacing exceeds the typical range for standard PPO designs.
Differential pressure gas-lift valves feature two ports, opening at lower differential pressures between injection and production, and closing at higher differentials They are designed with production pressure lines parallel to injection pressure lines, with a maximum differential pressure of approximately 2447 kPa (355 psi) and a normal differential pressure around 1724 kPa (250 psi) These valves require a maximum mandrel spacing of 152.4 m (500 ft) and are typically utilized in specific situations, such as when testing casing with the valves installed The elevated casing pressure during testing forces the valves to close, enabling effective pressure testing of the casing.
5.2.5.2.5 Surface Operated Gas-lift Valves
Surface operated gas-lift valves are managed from the surface through electrical or hydraulic signals that control their opening and closing These valves operate without the need for additional casing (injection) pressure drop.
To ensure continuous production from a well, it is essential to consider the potential need for an alternative valve in case the surface-controlled valve fails Consequently, adopting a conservative approach in mandrel spacing design is recommended.
5.2.5.2.6 Valve or Orifice at Operating Depth
In gas-lift mandrel design, utilizing an orifice or a specialized valve at the bottom is common, but it should not affect the mandrel spacing If the operational depth is uncertain, it is advisable to prepare for an unloading valve instead of positioning an orifice midway in the well Subsequent evaluations may reveal the necessity to substitute an unloading valve with an orifice at various depths within the well.
Gas-lift Mandrel Spacing Production Pressure Design Line Options
Gas-lift mandrel spacing is determined using design casing and tubing pressure gradients, along with several assumptions The production pressure design options include: a) Tubing Pressure Gradient Curve, which is not advisable for mandrel spacing due to the unknown production rate; b) Equilibrium Curve, which cannot be defined during mandrel spacing design but is suitable for valve settings; and c) Straight-line Approximation, the most effective method for mandrel spacing design, though not recommended for valve settings where more accurate information is available.
Using a vertical multiphase pressure gradient curve for production pressure design is not advisable, as the well does not operate on this curve during the unloading phase Initially, the well primarily displaces completion fluid from the annulus As unloading progresses, it starts to produce fluid from both the formation and the annulus Ultimately, once fully unloaded, the well will exclusively produce formation fluid from the reservoir.
The equilibrium curve illustrates the actual production rate during gas-lifting from a specific depth, necessitating an understanding of the well's inflow performance, which is often unavailable during mandrel spacing design Instead of relying on a single equilibrium curve, one could utilize multiple curves to represent varying inflow performances; however, this approach is labor-intensive A simpler method outlined in Annex B effectively achieves similar results with less effort.
5.3.4 Variable Rate or 20 % Design Line Method
This method uses a straight line for the production pressure design line It is constructed as follows
1) Top Point—The top of the design line is set at a point equal to Equation (1)
P t is the design tubing-head pressure; and
P c is the design casing-head pressure
2) Bottom Point—The bottom of the design line is set at a point equal to P c (at depth)—1379 kPa (200 psi) The advantages of this method are as follows
— Simplicity—Both the casing (injection) pressure design line and the tubing (production) design lines are straight lines
The positioning of the top and bottom points in the formula can be easily adjusted horizontally to meet specific needs For example, to place the mandrels closer together at a higher elevation in the wellbore, simply shift the top of the production pressure design line to the right, potentially aligning it with the value indicated in Equation (2).
To achieve closer spacing of the mandrels deep within the well, adjust the bottom of the line to the right, such as positioning it at P c (at depth)—689 kPa (100 psi) The aforementioned guidelines have proven effective in numerous cases.
5.3.5 Specific (Set) Differential Pressure from Casing Pressure
An alternative approach for selecting the production pressure design line is to apply a constant differential or offset from the injection (casing) pressure design line, particularly if a differential valve is being considered However, this method leads to uniform mandrel spacing, which is typically not ideal Ideally, mandrels should be positioned closer together at greater depths, as the casing pressure and production pressure lines converge deeper within the well.
5.3.6 Bracketing to Add Additional Mandrels Deep in the Well
For optimal performance, it is advisable to position mandrels just above the dual production packer When the spacing between design mandrels falls below a specified distance, the standard practice is to maintain a consistent vertical separation of 91.4 m to 152.4 m (300 ft to 500 ft) between the bottom mandrels This approach ensures that, in the event of a decline in the well's reservoir pressure or productivity over time, gas injection can occur from the deepest possible point within the well.
Gas-lift Mandrel Spacing Design Procedure
A number of factors should be considered in performing a gas-lift mandrel spacing design These are listed below A recommended design procedure is shown in detail in Annex B
The following pressures should be defined for the unloading design process
Kickoff casing (injection) pressure refers to the maximum gas pressure that can be delivered to the wellhead, which is crucial for the initial unloading process This pressure is utilized to displace completion fluid from the annulus, while the gas injection rate into the annulus remains minimal during this phase.
The kickoff pressure safety factor typically ranges from 0 kPa to 345 kPa (0 psi to 50 psi) to ensure a safe unloading design This range is crucial for providing sufficient pressure to initiate the unloading process effectively.
The operating casing (injection) pressure refers to the injection pressure that can be delivered to the wellhead at the specified design unloading rate This pressure is crucial as it is utilized when gas injection commences into the top gas-lift valve.
Casing pressure reduction for each deeper gas-lift mandrel is essential to ensure that the upper valves close while operating on the lower valves Typically, a pressure drop ranging from 0 kPa to 345 kPa (0 psi to 50 psi) is utilized, with a common value of 207 kPa (30 psi) being appropriate for optimal performance.
3.81 cm (1.5 in.) gas-lift IPO gas-lift valves are used
NOTE This casing pressure drop is required when spacing for IPO gas-lift valves It is usually not required when spacing for PPO gas-lift valves
— Operating Tubing (Production) Pressure—This is the production pressure that is needed to flow liquid produced from the well to the production facility
— Production Pressure Safety Factor—This is the amount, normally between 0 kPa and 345 kPa (0 psi and
To ensure safe unloading design, a production pressure of 50 psi is implemented, guaranteeing sufficient pressure to effectively extract fluid from the well during the unloading process.
The following fluid gradients and associated parameters should be defined for the unloading design process
— Completion Fluid Gradient—This is the pressure gradient (in kilopascals per meter or pounds per square inch per foot) of the completion fluid in the annulus
The gas gradient refers to the pressure gradient of the gas-lift injection gas, measured in kilopascals per meter or pounds per square inch per foot This gradient is influenced by several factors, including the gravity of the injection gas, the injection pressure, the temperature at the wellhead, and the temperature at depth within the well.
The following other factors are required for the unloading design process
The Mandrel Depth Safety Factor is the reduction applied to each calculated mandrel depth to ensure the unloading process remains safe Each mandrel is positioned between two tubing joints, with a typical safety factor ranging from 0 m to 15.2 m (0 ft to 50 ft).
— Minimum Mandrel Spacing—This is the minimum mandrel spacing distance It is expressed in vertical as opposed to measured depth units A typical value is between 91.4 m to 152.4 m (300 ft to 500 ft)
— Depth of Upper Zone Production Packer—This is the depth of the upper zone’s production packer It should be known in both true vertical and measured depth terms.
Installation Issues
5.5.1 Installing the Two Tubing Strings Separately
In certain situations, it is essential to install the dual tubing strings separately, starting with the long string When doing so, the second (short) string and its mandrels must be positioned beyond the first (long) string and its mandrels Both the long string production packer and the short string or dual packer should be installed on the long string, with the short string being connected to the short string or dual packer during its installation.
5.5.2 Installing and Pulling Both Zones at the Same Time
The standard procedure for a dual completion involves ensuring proper spacing between gas-lift mandrels on both strings This design allows for the removal of tubing and mandrels from one zone without interference from the other zone's components.
When One Zone Is Much Deeper than the Other
Dual gas-lift is not advisable when the upper and lower zones are excessively distant, typically exceeding 305 m (1000 ft) In instances where well zones are further apart, alternative solutions can be explored.
5.6.2 Alternatives Where Two Zones Are Vertically Far Apart
Utilize an injection string positioned below the upper packer with side-string mandrels, allowing for a separate injection tube installation beneath the upper packer This design accommodates three tubing strings and connects to the gas-lift mandrels in the long string, which are installed beneath the upper packer This setup enables deeper gas injection into the deep zone's tubing while isolating the injection gas from the short zone's production interval.
For optimal gas-lift design, if the tubing diameter permits, both gas-lift strings should extend to the depth of the upper zone's dual production packer However, this method has a significant drawback: it restricts the ability to inject gas into the deeper lower zone of the dual well.
— An insert string may be used in the long side of the dual to inject gas into the long side beneath the dual zone production packer
— If the casing is large enough to accommodate a three-hole packer and an injection line beneath the dual packer, use the approach illustrated in Figure 1
When the long string tubing is insufficient for an insert string and the casing cannot support a three-hole packer along with an injection line below the dual packer, it is essential to design mandrels only to the depth of the upper dual zone packer.
5.6.2.2 Design Both Sides Down to the Dual Packer
The most straightforward solution involves designing both gas-lift strings to reach the depth of the upper zone's dual packer However, this method has a significant drawback: it prevents the injection of gas into the deeper lower zone of the dual well.
An alternative approach involves utilizing an injection string located beneath the upper packer, featuring side-string mandrels This design incorporates a separate injection tube installed below the upper packer, which is designed to support three tubing strings and connects to the gas-lift mandrels in the long string These mandrels are positioned beneath the upper packer, allowing for deeper gas injection within the deep zone's tubing while effectively isolating the injection gas from the production interval of the short zone.
Figure 1—Mandrel with Injection String Beneath the Upper Packer
A concentric snorkel, or dip tube, offers an effective method for deeper injection within the long string This design features an injection tube positioned below the upper dual packer, allowing it to be concentric within the long string tubing instead of being externally attached Gas can be injected through the well's annulus into the dip tube and subsequently into the deep zone's tubing string This can be achieved by injecting around the dip tube's end, although this method is not recommended, or by utilizing gas-lift valves installed within the dip tube This approach is viable when the long string's tubing size can accommodate a concentric injection string.
To safely commingle two zones, inject down the short string beneath the dual packer, ensuring that the pore pressure gradients of both the short and long string zones are equal to prevent significant cross-flow when the wells are closed If the flowing bottomhole pressure (FBHP) in the upper zone is anticipated to be lower than the lift gas pressure at depth, the long string can serve as the production string while the short string delivers gas to the upper zone perforations.
To achieve the desired outcome, first, open a sliding sleeve near the upper perforations or perforate the long string tubing at the upper zone depth Next, install unloading valves in the mandrels of the long string, including the lowest mandrel Then, place dummy valves in all mandrels of the short string except for the lowest one Finally, install a gas-lift orifice in the lowest mandrel of the short string, ensuring it is sized to provide the necessary lift gas rate.
To operate the well: a) leave the short string wellhead valves closed, b) open the long string wellhead valves, c) inject lift gas into the casing
The unloading valves in the long string facilitate the unloading of the well to the depth of the lowest mandrel Subsequently, the gas-lift orifice located at the lowest mandrel of the short string allows gas to flow from the casing into the tubing, reaching the depth of the perforations or the open sliding sleeve near the upper zone's perforations Typically, the lift gas rate is regulated for optimal performance.
PPO and IPO Gas-lift Valves Compared
Some believe that the only suitable gas-lift valve for a dual gas-lift well is the PPO type, as it allows the production pressure of each zone to dictate valve operation, rather than relying on a common injection pressure that may not effectively serve both zones Others argue for the selection of IPO valves, citing their superior control for unloading the well.
Accurate performance models for IPO and PPO gas-lift valves are provided by API 19G2, which outlines methods for testing and developing these models Many widely used IPO and PPO valves have been modeled according to API 19G2 standards These models are essential for designing opening and closing pressures and for calculating gas flow rates across various operating pressures.
PPO gas-lift valves in dual wells present various arguments and considerations While these valves do not completely isolate the well from fluctuations in injection pressure, they exhibit lower sensitivity to such changes compared to IPO valves.
PPO valves primarily rely on production (tubing) pressure for their opening and closing mechanism, making them less sensitive to fluctuations in injection pressure compared to IPO valves This characteristic can be advantageous in various applications.
PPO valves are essential when there is a potential for significant fluctuations in gas-lift system pressure Implementing proven techniques can help maintain a stable system pressure, thereby preventing operational disruptions.
5.7.2.3 PPO Valves Crossover Port Flow Restrictions
Certain PPO valves have experienced limitations in gas flow through their crossover ports, while others have been re-engineered to enhance this aspect To assess the performance of a specific PPO valve, it is essential to conduct testing and modeling in accordance with API 19G2 standards for accurate evaluation.
PPO valves are fixed and do not self-adjust; they operate at predetermined injection and production pressure values Consequently, if the production pressure fluctuates due to variations in the well's productivity, an upper unloading valve may reactivate at the increased production pressure, enabling the well to function effectively at higher levels.
5.7.2.5 Spring-loaded PPO Valve Temperature Insensitivity
Using a spring instead of a nitrogen gas charge for the closing force in valves makes them insensitive to well temperature However, this characteristic does not provide an advantage for PPO valves over IPO valves, as both types can utilize a spring in place of nitrogen gas.
5.7.2.6 Using IPO Type Valves on Both Sides of Dual Gas-lift Wells
Unloading valves are essential for removing liquid from the annulus, allowing gas-lift gas to be injected to the desired depth While IPO valves are widely recognized and commonly used for unloading single-string gas-lift wells, they are also the optimal choice for dual systems where both sides can be unloaded to the bottom and operated from there.
In dual wells, alternative valve types are frequently suggested to ensure that one or both sides can maintain operation at a higher point without lifting from the deepest operating level.
In gas-lift wells operating "up the hole," it may be beneficial to utilize a valve that opens based on tubing pressure rather than casing pressure If either side of a dual system requires lifting from "up the hole," it may necessitate a redesign of the gas-lift valves or the consideration of alternative valve types For instance, if it's established that one side of a dual must lift from the third mandrel, IPO valves can still be effectively employed by installing an injection orifice in the third mandrel.
For optimal performance in dual well operations, IPO valves are recommended if both sides can be effectively unloaded to the desired operating depth and maintained at that level This is particularly relevant when adjustments in operating depth occur in one zone, allowing for the redesign of the gas-lift string to position an operating valve or orifice accordingly However, if there is uncertainty about achieving the desired depth on either side of the dual well, or if the actual operational depth is unknown, IPO valves may not be the most suitable option.
5.7.2.7 Injection Pressure Drop to Close Upper Valves
With IPO valves, there is a need to take an injection pressure drop from valve to valve to close upper valves
The injection pressure is the main force that opens and closes IPO valves, necessitating a pressure drop between each depth to ensure upper valves close when injecting through a lower valve Consequently, gas-lift mandrels must be positioned closer together compared to valves that do not require a casing pressure drop.
5.7.2.8 Upper Mandrel Spacing Too Far Apart for PPO Valves
When upper mandrels are spaced too far apart, the use of IPO valves may be necessary The IPO design allows for a wider mandrel spacing compared to other valve types, despite requiring an injection pressure drop between valves This is because the tubing pressure design line for IPO valves can be positioned lower than that for other valves If it is assured that neither side of the dual well will need to inject in the upper section, implementing IPO valves should not pose any issues.
5.7.2.9 Switching from IPO Valves to PPO Valves
Operators can utilize IPO valves in top mandrels that are spaced further apart, allowing for effective unloading in the upper section of the well, where operational needs are minimal As they move deeper into the well, where gas injection may be necessary, they can switch to PPO valves to ensure optimal performance.
Unloading Gas-lift Valves
Annex C contains an unloading valve design for PPO gas-lift valves Gas-lift mandrel example spacing design is included in Annex B
5.8.2 Unloading Valve Design for Each Type of Valve
A standard design for PPO gas-lift valves can be found in Annex C, along with various design programs that provide information on alternative valve designs Available options for unloading valves consist of PPO gas-lift valves, IPO gas-lift valves, and balanced IPO gas-lift valves.
Operating Unloading Gas-lift Valves
The actual depth of gas-lift injection is often uncertain and difficult to predict, especially in new completions or when reservoir pressure, inflow productivity, or fluid properties fluctuate In such cases, operating from an unloading valve may be necessary, either for the long term or until the true lift depth is established By selecting and designing the unloading valve to minimize throttling, acceptable operation can be achieved Additionally, if well conditions change, the depth of lift can automatically adjust to a different valve.
It may be necessary to operate from more than one unloading valve In some instances, where the casing
When injection pressure is low, achieving the desired injection rate at deeper mandrel depths can be challenging In these situations, employing multipointing or simultaneous injection into multiple valves may prove advantageous Additionally, injecting gas through an upper valve can reduce the tubing pressure gradient, facilitating increased gas injection into the deeper valve, provided the correct valve type is utilized.
To enhance well performance, it is advisable to install an orifice, nozzle venturi orifice, or "flag" valve in the deepest mandrel on both sides of the dual, especially if gas injection through an upper unloading valve is expected This setup allows for monitoring if the well operates down to the deepest mandrel For anticipated injection through an upper unloading valve, the use of PPO or balanced IPO valves is recommended, as they enable the determination of lift depth based on the well's producing conditions In contrast, using IPO valves would make the operating valve reliant on changes in casing pressure rather than the well's production conditions.
5.9.2 Alternatives for Operating Gas-lift Valve or Orifice
For gas-lift injection at the designated operating depth, options such as an unloading gas-lift valve, a standard orifice, a nozzle venturi orifice, or a "flag" valve can be utilized In dual gas-lift designs, these alternatives are employed at specific operating points When the desired operating depth is established, it is advisable to opt for a standard orifice, nozzle venturi orifice, or "flag" valve Conversely, if the operational depth is uncertain or unpredictable, an unloading valve may be used.
Operators often install an orifice at the known depth of lift, such as from the deepest gas-lift mandrel, to ensure it remains fully open This design allows the orifice to handle a wide range of gas injection rates without throttling, provided the flow is not in the critical range Critical flow is defined as occurring when the tubing pressure downstream of the orifice falls below approximately 60% of the upstream casing pressure.
To optimize well performance, the injection rate must be adjustable within a range that prevents excessive pressure from reopening an upper valve A key challenge with orifice valves is selecting the appropriate orifice port size; if the port is too large, it can lead to well instability Therefore, the orifice size should be carefully determined to facilitate the correct gas injection rate while maintaining flexibility and stability Additionally, orifice valves are equipped with a built-in check valve to prevent backflow from the tubing to the casing annulus when tubing pressure exceeds casing pressure.
For effective gas injection in dual gas-lift wells, a nozzle venturi orifice can be utilized when the desired injection rates are known This specialized orifice features a venturi design that enables critical flow when the downstream pressure is below approximately 92% of the upstream pressure, allowing for a consistent gas injection rate This capability is particularly beneficial for maintaining the desired injection rates on both sides of the dual gas-lift system, provided that the upstream casing pressure is stable and the downstream tubing pressure remains below the critical threshold However, unlike a simple orifice, the nozzle venturi lacks the flexibility for real-time adjustments to the gas injection rate, necessitating that the desired rate be predetermined and the venturi sized accordingly.
5.9.5 Flag Valve (PPO, IPO, Balanced IPO Designs)
Some operators opt for a "flag" valve in the bottom gas-lift mandrel instead of an orifice or nozzle venturi This type of valve, which can be a normal PPO, IPO, or balanced IPO valve, is engineered to function at a lower injection pressure than unloading valves Typically, it remains fully open due to the injection and production pressures at depth; however, it has the capability to close if the pressures drop too low, unlike an orifice or nozzle venturi.
Designing for Dual Gas-lift if Mandrels Spaced Too Far Apart
When upper gas-lift mandrels are spaced too far apart, utilizing PPO or similar gas-lift valves may not be feasible In such situations, it becomes essential to consider IPO valves or alternative methods to effectively unload the well.
5.10.2 IPO Valves in Upper Mandrels
IPO valves are essential for upper mandrels, offering compatibility with wider mandrel spacing compared to PPO or balanced IPO valves If the likelihood of operating from these upper mandrels is low, opting for IPO valves is a sensible decision.
5.10.3 Use of Pack-off Valves
If for some reason use of IPO valves does not appear feasible, use of a pack-off valve can be considered
If the upper mandrel spacing is excessively wide, even for IPO valves, a pack-off valve may be required This involves punching a hole in the tubing and positioning the pack-off valve over it However, a significant drawback is that wireline work cannot be conducted beneath the pack-off device without its removal.
An alternative solution for unloading in production systems is to install insert concentric tubing within the primary production tubing, provided the latter is sufficiently large This concentric tubing can be equipped with essential gas-lift mandrels and valves to facilitate the unloading process.
Dual Gas-lift System Design Options
This section outlines various options for choosing gas-lift valves suitable for dual gas-lift systems While this RP does not aim to provide specific recommendations, it presents these options for the consideration of operators managing dual gas-lift wells.
5.11.2 PPO Valves on Both Sides
Operators often opt for PPO valves on both sides of a dual gas-lift well, typically installing an orifice or venturi orifice valve at the lowest operating valve This approach is generally motivated by two main reasons.
1) use of PPO valves can allow the well to work down with less loss in casing pressure; and
PPO valves offer superior accommodation for gas flow discrepancies between zones in a dual system compared to IPO valves, as they allow for more precise control of valve operation based on injection pressure.
5.11.3 IPO Valves High in the Hole, PPO Valves Lower in the Hole
Some operators suggest it may be preferable to use IPO valves higher in the well and PPO valves lower
Using IPO valves for unloading a well is often more efficient, while PPO valves are recommended for the lower section where most operations occur This approach is justified as a dual well requires a single unloading to clear liquid from the casing/tubing annulus, effectively achieved with an IPO design Once the well is unloaded, the operation can be optimized by employing PPO valves at the operating depth.
5.11.4 IPO Valves on One Side, PPO Valves on the Other Side
An alternative method involves using IPO valves on one side of the dual and PPO valves on the other This strategy allows for unloading the well using the IPO valves while keeping the opposite side closed Once the unloading is complete, the well can be transitioned to gas-lift with both sides open, ensuring a more reliable unloading to the bottom However, this approach has potential drawbacks, including a reduction in casing pressure due to unloading with IPO valves and the possibility of the IPO side "robbing" gas from the PPO side.
To optimize gas-lift operations, it is essential to utilize small-ported gas-lift valves and a small orifice to regulate gas flow effectively Additionally, incorporating chokes in the gas-lift valves can further enhance control and prevent excessive gas intake on either side.
5.11.5 IPO Valves on Both Sides
An alternative approach involves utilizing IPO valves on both sides, which can be effective if the characteristics of both zones are well understood, including the depth of lift and gas requirements However, accurately predicting these factors is often challenging Changes in one or both wells may necessitate adjustments to the injection rate, making it difficult to manage with IPO valves installed on both sides.
In scenarios where adequate gas injection pressure allows for bottom injection without the installation of unloading valves, single-point injection can be effectively implemented through an orifice positioned just above the dual packer This method proves efficient when the orifice sizes are carefully selected to avoid over-injection.
6 Dual Gas-lift Well Operations