Troubleshooting of Gas-lift Installations 1 Gas-lift Operating System Components and Potential Problems 1.1 Gas-lift System Components The primary components of the gas-lift production
Purpose
A gas-lift system comprises various components that require thorough understanding, operation, and maintenance For optimal efficiency and cost-effectiveness in artificially lifting wells, these components must work in harmony.
This document outlines the key components of continuous gas-lift systems and provides a summary of best practices for identifying and resolving issues that can lead to operational inefficiencies A checklist is included as a quick reference for recognizing and addressing common problems associated with continuous gas-lift operations It is important to note that this document does not cover intermittent gas-lift, which is discussed in API 11V10.
Gas-lift System Components
The primary components of the gas-lift production system are:
— surface gas-lift compression, dehydration, and distribution system;
— gas injection metering and control equipment;
— well equipment—tubulars, completion, and wellhead;
— gathering system—flowline and manifold;
— well production rate testing facility;
Each of these components is shown on Figure 1 and is discussed in the sections that follow, along with specific recommended practices to reduce inefficiencies and unstable operations.
Gas-lift System Operating Problems
Gas-lift systems often face operational challenges, particularly under-lifting, where wells receive insufficient gas for effective lifting To address this issue, it is essential to implement recommended practices outlined in section 2.1.
— provide monitoring and control equipment and procedures;
— compare actual vs design/optimum gas-lift performance;
— assure gas-lift valves and other equipment are working properly;
— allocate the available supply of gas to the most profitable wells in an optimal way when the supply is limited. b) Wells are being over-lifted (too much gas), see 2.1:
— provide monitoring and control equipment and procedures;
— compare actual vs design/optimum gas-lift performance;
To optimize gas management, it is advisable to either reduce compression or sell any excess gas rather than attempting to inject all of it when the overall gas supply is excessive Additionally, ineffective gas-lift distribution due to poor distribution control can hinder performance.
— evaluate overall system constraints, including gas-lift compression, distribution, wells, and handling systems;
— distribute or allocate available gas to each well by considering both the gas distribution system and the wells.
Figure 1—Gas-lift System Components d) Gas-lift wells are unstable (injection and/or production heading), see 2.3 and Section 4:
— provide monitoring equipment to detect unstable operation;
— determine the cause(s) of the instability;
— eliminate or reduce injection heading; it is very inefficient. e) Wells have other problems (equipment, instrumentation, etc.), see 2.5:
— consider all components of the gas-lift system;
— monitor and calibrate all system components;
— establish and practice quality assurance on equipment selection and installation.
Surface Facility Problems
Typical problems with the surface gas-lift compression, dehydration, and distribution system, and recommended practices to deal with them are as follows. a) Compression problems, see 3.1:
— maintain the compression facility to provide a consistent supply of lift gas at a stable pressure;
To ensure an optimal balance between gas demand in the wells and supply from the compressor plant or other sources, it is essential to monitor the compressor output and adjust the injection rates accordingly.
— perform routine compressor preventive maintenance to maximize system availability. b) Dehydration problems, see 3.2:
To prevent hydrate formation in gas-lift operations, it is essential to dehydrate gas to less than 7 lb (3.175 kg) of water per million cubic feet (28,317 cubic meters) of gas For operations in cold climates, the optimal water content is recommended to be 3 lb (1.36 kg) of water per million cubic feet (28,317 cubic meters).
To optimize system design, it is essential to minimize large pressure drops The API advises incorporating a "surge factor" of 40% to 50% when sizing pipes for gas-lifted production, in contrast to a 20% surge factor for naturally flowing wells.
— purge liquid from gas-lift distribution lines periodically;
— install insulation to reduce ambient temperature effects on freezing problems. c) Distribution system problems, see 3.3:
— use a “finger” style gas-lift distribution system (see Figure 8);
— make the volume of the system as large as economically feasible;
— avoid combining continuous and intermittent lift in the same gas-lift distribution system unless automatic control is used;
— measure the total gas into each group of wells to assist with allocation and troubleshooting.
Metering and Control Problems
Typical problems with the gas-lift injection metering and control equipment, and recommended practices to deal with them are as follows. a) Gas injection metering problems, see 4.1:
— use properly installed, ranged, well maintained, and accurately calibrated meters;
— measure injection pressure at the wellhead, downstream of any obstacles;
— pay special attention to gas measurement accuracy during well tests and pressure surveys. b) Gas injection control problems, see 4.2:
— operate close to the design conditions of the gas-lift installation;
— redesign and re-install the gas-lift valves if the well's conditions have changed enough to disturb effective operation;
— use a properly ranged gas flow controller to provide consistent, stable flow.
Gas-lift Valve Problems
Typical problems with the unloading and operating gas-lift valves, and recommended practices to deal with them are as follows. a) Unloading valve problems, see 5.1:
— check the well performance of each well to detect heading or valve operating problems;
— use small-ported unloading valves to facilitate deeper valve transfer and prevent over injection at upper valves;
— or, use downstream chokes in unloading valves to minimize throttling, avoid over injection, and minimize damage to the valve port and seat during the unloading process;
— follow the unloading procedures in Section 12 to work down to the desired operating valve and avoid valve damage during unloading operations. b) Operating valve problems, see 5.2:
— use an orifice rather than a gas-lift valve in high productivity index (PI) wells [more than 0.5 B/D/psi (.012 m 3 / D/kPa)] to prevent throttling and permit a wider range of gas injection rates;
In low permeability (PI) wells, utilizing a gas-lift valve is essential to avoid over-injection and maintain adequate casing gas pressure, thereby preventing the formation of hydrates at chokes and excessive gas withdrawal from the distribution pipeline.
— use a choke downstream of the orifice to protect the orifice and avoid over injection;
— redesign and re-install the operating valve/orifice if well conditions change enough to disturb effective operation.
Well Equipment Problems
Typical problems with gas-lift well equipment such as tubulars, completion equipment, and wellheads, and recommended practices to deal with them are as follows. a) Casing annulus problems, see 6.1:
— use a casing scraper during workovers to clean debris from the casing wall;
— circulate fluid to insure that the annulus is clean;
— hydrostatically test to gas-lift injection pressure to assure casing integrity;
Avoid lifting two well completions in a single casing annulus, and if dual gas-lift is necessary, consult API 11V9 For tubing issues, refer to section 6.2.
— circulate fluid to clean the tubing of corrosion products, scale depositions, paraffin, and asphaltine If tubing has excessive deposits, pull and replace it with a clean string;
— remove any unnecessary obstacles, such as unnecessary safety valves;
— use a mechanical set permanent or retrievable packer that holds in both directions;
Utilize an on-off tool featuring a profile nipple that allows for the installation of an X-plug with an equalizing prong within the profile This plug can be positioned when the tubing and valves are removed, effectively preventing kill fluid from damaging the reservoir formation For further details on completion issues, refer to section 6.3.
— run flowing bottomhole pressure (FBHP) and static bottomhole pressure (SBHP) surveys at least annually to assess and track well performance and reservoir productivity;
— stimulate a well if its productivity becomes impaired and a pressure build-up test indicates that skin may be the problem;
— minimize pressure surges and heading in a well that has sand producing reservoir rock or a sand control screen or gravel pack. d) Wellhead problems, see 6.4:
— minimize flow restrictions such as bends, choke bodies, etc.;
— provide safe and easy access for wireline work. e) Wellhead monitoring and control problems, see 6.5:
— measure the wellhead production pressure on a consistent basis;
— consider continuous measurement of the well's production rate using multiphase metering or production flow rate estimating technology.
Gathering System Problems
Typical problems with gathering system equipment, including the flowlines and manifold, and recommended practices to deal with them are as follows. a) Flowline problems, see 7.1:
— keep the flowline clean and avoid unnecessary restrictions;
— use appropriate treatments if needed to remove scale deposits, paraffin, etc.;
— avoid using one flowline for more than one well; this is to minimize excessive backpressure and avoid complications in monitoring the production of each well. b) Manifold problems, see 7.2:
— minimize any unnecessary restrictions or pressure losses;
— keep all manifold valves fully open or fully closed;
— check the manifold for leaking valves using sonic or infrared detectors.
Well Testing Problems
Typical problems with well production rate testing equipment, and recommended practices to deal with them are as follows. a) Well test scheduling problems, see 8.1:
— test each well often enough to detect changes in performance;
— test each well long enough to obtain accurate results;
— co-ordinate well testing with other activities such as pressure surveys;
— use automatic or semi-automatic well testing to improve testing accuracy and reduce testing labor. b) Test separation problems, see 8.2:
— purge time is required to thoroughly flush the previous well's production from the system;
— maintain the test separator backpressure consistent with the production system pressure;
— check and calibrate the well test meters. c) Test measurement problems, see 8.3:
— make well testing a high priority so it receives the attention it deserves.
Production Handling Problems
Typical problems with production handling equipment, and recommended practices to deal with them are as follows. a) Oil handling problems, see 9.1:
— measure total oil produced from each set of wells for comparison with estimates and for allocation and troubleshooting purposes. b) Water handling problems, see 9.2:
— measure or estimate total water production from each set of wells for comparisons and for allocation and troubleshooting purposes. c) Gas handling problems, see 9.3:
— measure gas production from each set of wells for comparisons and for allocation and troubleshooting purposes.
Information Handling Problems
Typical problems with information handling, and recommended practices to deal with them are as follows. a) Well test information problems, see 10.1:
— detect and evaluate “good,” vs “questionable,” vs “bad” well tests;
— re-test wells if the data is questionable;
— fix the problem that creates a bad test and then re-test the well;
— use the good well tests to evaluate actual performance and allocate gas-lift production. b) Downtime information problems, see 10.2:
— detect and account for all downtime;
— use this data to allocate production to the wells, calculate production deferment due to downtime, and prioritize remedial work;
— keep unplanned downtime to a minimum;
To calculate the average calendar-day contribution from groups of lifted and naturally flowing wells, combine well downtime with facility downtime to determine the operating factor, which represents the fraction of online time By multiplying this operating factor by the daily oil production, you can assess the performance of each well group Additionally, refer to section 10.3 for issues related to pressure and temperature survey information.
— obtain pressure surveys annually, or when conditions change;
— follow the procedures in Section 10 to obtain accurate results;
— obtain a pressure build-up if the inflow performance has changed. d) Gas injection pressure and rate measurement information problems, see 10.4:
— monitor and continuously record the injection pressure and rate;
— gather this information during well tests, pressure surveys, and unloading;
— use this and related information to perform gas-lift surveillance and build accurate gas-lift models. e) Wellhead (production) pressure and temperature information problems, see 10.5:
— monitor and continuously record the production pressure;
— gather this information during well tests, pressure surveys, and unloading.
Surveillance and Control Problems
Typical problems with the gas-lift surveillance and control system, and recommended practices to deal with them are as follows. a) Manual operating problems, see 11.1:
— provide on-going training in all aspects of gas-lift operation;
— provide quality measurement and control equipment;
— perform periodic system reviews to identify bottlenecks and opportunities;
— become familiar with the following checklist for use if problems develop in gas-lift wells.
1) is the master valve open?
2) is the wing valve open?
3) is the operating gas-lift valve open?
4) is the downhole safety valve open?
5) is the well's flow rate slugging?
6) is there a choke in the flowline?
7) is the gas-lift injection rate correct?
8) is the gas-lift injection pressure reasonable?
9) is the gas-lift injection pressure heading or surging?
10) is the flowing wellhead pressure reasonable?
11) is the flowing wellhead temperature reasonable?
12) is the separator pressure reasonable?
13) is hydrate forming at chokes or low spots in the piping?
14) is well test data (oil/water/gas) reasonable and reliable? b) Production automation, see 11.2:
— use production automation to improve operational effectiveness.
Purpose
A gas-lift system requires a consistent supply of lift gas, delivered to the wells at a stable pressure and flow rate To ensure reliable operation, all system components—including gas-lift valves, tubulars, wellheads, flowlines, and separation and treating facilities—must be appropriately sized.
If one or more of the system components are not working as intended, one or more problems can arise:
— wells may be “under-lifted,” resulting in lost or deferred production;
— wells may be “over-lifted,” resulting in excess consumption of gas and/or lost production;
— lift gas may be ineffectively distributed, resulting in sub-optimum system performance, even if all other parts of the system are designed adequately;
— wells may be unstable; this can lead to a large number of problems.
Under-lifted and Over-lifted Wells
A gas-lift well is considered "under-lifted" when the gas injection depth is insufficient for optimal lift or when the gas injection rate is inadequate These factors result in inefficient gas utilization and reduced production levels.
A gas-lift well is considered "over-lifted" when the gas injection rate or pressure is excessively high, resulting in inefficient gas utilization This situation leads to suboptimal gas-lift performance, where a significant increase in injection gas yields minimal production gains or even a decrease in output The goal is to effectively utilize the available injection gas to maximize overall oil production rates.
When the compressor capacity surpasses the optimal gas injection needed for a group of wells, flow stability criteria become essential Achieving stability necessitates maintaining a velocity of approximately 6 ft/s (1.83 m/s) in the gas-lifted mixture within the tubing string above the injection point.
The following practices are recommended for under-lifted and over-lifted wells
To optimize gas-lift well performance, conduct flowing and static pressure surveys alongside precise well test and injection data This approach helps estimate current producing gradients, gas-lift injection depths, flowing bottomhole pressures, and inflow performance Utilize this information to develop a calibrated computer model for effective surveillance and troubleshooting Additionally, apply these methods to natural flow wells that are anticipated to undergo artificial lifting in the future.
Utilize a calibrated computer model under current operating conditions to identify wells experiencing under-lifting This approach enables the prediction of the optimal gas-lift injection rate, pressure, and depth, as well as the anticipated increase in production by addressing the issue effectively.
— Maintain the desired gas-lift injection control with a gas measurement system and an automated control valve to maintain the desired injection rate and pressure.
Identify over-lifted and under-lifted wells through flowing gradient surveys and production tests that incorporate injection gas measurement The gas conserved in one set of wells can be effectively utilized in other wells for increased profitability.
To achieve stability in gas-lift operations, it may be necessary to temporarily over-inject in certain wells, aiming for a mixture velocity of approximately 6 ft/s (1.83 m/s) above the injection point If this condition continues, a redesign of the well is essential to address the instability issue Most gas-lift computer models are capable of calculating the required mixture velocity.
— Evaluate the effects on surface facilities caused by over-injection in wells, if this practice is used to maintain stability.
Ensure that gas-lift valves are correctly constructed, assembled, and adjusted prior to installation Utilize gas-lift valves that meet API 11V1 specifications (or ISO 17078-2 upon its release) For repair and reassembly, refer to API 11V7 (or ISO 17078-2 when available).
To ensure compliance with design specifications for critical applications or in the presence of ongoing issues, it is essential to check and probe test individual valves Refer to API 11V2 for guidelines on gas-lift valve testing and modeling, noting that this document will be superseded by ISO 17078-2 upon its release.
To optimize production, identify under-lifted wells and assess any gas supply issues caused by pipeline restrictions or limited compressor capacity Evaluate these wells to establish production priorities and determine the best gas-lift allocation, following the guidelines outlined in API 11V8.
To ensure stable deep injection, it is crucial to monitor the frequency of compressor shutdowns, as frequent interruptions can hinder well performance Redesigning unloading valves with smaller ports or chokes and adjusting gas injection control may be necessary Additionally, compressor downtime should be limited to no more than 5%.
2.1.2 Well Under-lifted—Injection Too Shallow
To ensure proper lifting of a well, gas should be injected at the optimal design depth Typically, the ideal lift point is located within three joints, approximately 100 feet (30.48 meters) above the production packer; however, the actual lift point may vary based on specific conditions.
— available gas-lift system pressure
If injection occurs through an upper unloading valve or a leak, the well's flowing bottom hole pressure (FBHP) cannot be reduced to the desired level, resulting in a lower than expected production rate This issue can arise from various underlying problems.
— lower than desired injection gas pressure;
— improper gas-lift mandrel spacing;
— valves that are not assembled or set properly; valves that are installed in the wrong mandrels; use of the wrong types of valves, or ports that are too large;
— leak in an upper unloading valve, upper mandrel, tubing, or connection;
— well not properly unloaded; it never reached the intended operating valve;
— other problems that do not allow the well to work down to its design injection depth are restrictions at the surface, inadequate injection control, and frequent shutdowns
2.1.3 Well Under-lifted—Injection Rate Too Low
Continuous gas-lift design determines the necessary gas injection rate to maintain an optimal pressure gradient from the gas entry point to the surface Insufficient gas injection can lead to an excessively heavy gradient, preventing the well from reaching the desired flowing bottomhole pressure, even if the injection is set at the correct operating valve or orifice Consequently, this may cause the well to produce at a rate lower than its potential.
NOTE By injecting through an upper gas-lift valve, even with the same amount of gas, the operating bottomhole pressure is increased and the production rate is reduced
Figure 2—Problem of Injecting Gas Through an Upper Gas-lift Valve
NOTE By not injecting enough gas, even through the same valve, the operating bottomhole pressure is increased and the production rate is reduced.
Figure 3—Problem of Under Injection—Injecting Too Little Gas
This condition can be caused by:
— rate of gas available to the well is less than design;
— gas composition/density is significantly higher or lower than design specific gravity;
— injection gas pressure available to the well is lower than design;
— flow restrictions at the surface;
— control choke or valve at the surface is improperly set and the injection rate is less than design;
— hydrates forming in the choke or gas line serving the well;
— the gas-lift valve port size, or choke size, is too small to accommodate the desired gas injection rate;
— increased water cut requiring additional injection gas to maintain the desired pressure gradient.
2.1.4 Well Over-lifted—Injection Rate Too High
A too high gas-lift injection rate should be avoided for practical reasons, as follows.
— May allow injection gas to enter an upper valve.
Excess gas may raise casing pressure above the set point for upper unloading valves, causing one to open with loss of efficiency and production rate.
Excess gas can increase friction in surface flowlines and tubing, leading to higher flowing bottom hole pressure (FBHP), reduced drawdown, and lower production rates When gas rates become excessive, friction loss can outweigh the benefits of reduced fluid density, causing an increase in pressure gradient, rising FBHP, and decreased liquid rates In continuous gas-lift wells, injected gas mixes with the liquid in the production stream, lightening the pressure gradient and reducing mixture density, which allows for lower production pressure drops As gas injection increases, production pressure decreases until it reaches the minimum pressure gradient, referred to as "Ideal Operation." It is important to note that the gas injection rate for continuous gas-lift wells should typically be significantly lower than the rate needed to achieve this minimum gradient.
Ineffective Gas Distribution
The ideal gas availability in a field should match the total optimum injection rates for gas-lift wells; however, this is rarely the case in practice Often, there is either an excess of gas leading to over-injection or a shortage of gas resulting in under-injection.
The following practices are recommended for effective gas distribution.
Regularly assess the performance of the system and each individual well to identify issues related to inefficient gas distribution Periodic evaluations can reveal patterns of problems, such as a situation where all wells in a specific area of a field are experiencing under-injection.
NOTE If the injection pressure is too high for any reason, it can cause an upper valve to open, leading to inefficient and very likely unstable lift operation.
High injection pressure can lead to the unintended opening of an upper valve, particularly when gas or hydrate formation occurs in low spots along the pipeline Additionally, wells located downstream of other unstable wells may experience instability, further complicating the situation.
— Use a map of the distribution system to indicate which wells are normal, and which are under-lifted, over-lifted, and/or unstable.
— Use system-wide solutions to address distribution bottlenecks, gas shortage or oversupply problems, or ineffective gas dehydration indicated by hydrate formation.
To ensure efficient gas distribution during compressor outages, it is essential to create a comprehensive plan that addresses various scenarios Refer to API 11V8 for an in-depth exploration of this process Implementing an automatic control system can significantly enhance the optimization of gas allocation.
Gas distribution to wells aims to maximize oil production, while optimization also considers the balance between gas compression costs and the value of the oil produced.
In situations of oversupply, it is more beneficial to sell excess gas rather than inject it ineffectively or into unstable wells Additionally, gas can sometimes be sold at an intermediate pressure lower than the final gas-lift pressure, which helps to reduce compression costs.
In cases of gas undersupply, it is essential to allocate less gas to lower priority wells, characterized by high water cut and low productivity, while prioritizing high productivity wells with low water cut During temporary compressor outages, shutting in the lowest priority wells allows for the continued effective production of more productive wells Additionally, in manually operated gas-lift systems, the installation of small port valves or chokes can help regulate the gas injection rate, ensuring that low priority wells receive minimal gas.
Gas-lift optimization involves identifying the ideal gas injection rate for each well and effectively distributing gas during shortages, as outlined in API 11V8, Section 7.
Unstable Gas-lift Operation
Unstable operation in gas-lift wells, distinct from the slug flow pattern in multiphase flow, is a significant challenge for continuous operation.
The following practices are recommended for unstable gas-lift operation:
— use pressure transducers to gather and display injection or casing pressure, and producing or tubing pressure;
— use a gas meter and flow computer to obtain gas injection rate (and upstream pipeline pressure and differential pressure);
— note patterns of instability and use these in gas-lift system analysis, as discussed in 2.2;
— see 2.4 to evaluate the type(s) or cause(s) of instability.
2.3.2 Unstable or Heading Gas-lift Operations Can Cause a Number of Problems
The following are possible problems arising from unstable or heading gas-lift operations.
— Excessive use of lift gas.
Unstable gas-lift operation occurs when gas is over-injected at certain times and under-injected at others, leading to wasted gas and ineffective usage This results in a poor ratio of injection gas to total liquid production, making unstable gas-lift heading less effective than steady flow Interestingly, increasing the rate of gas injection temporarily, along with other improvements to gas-lift design, may help mitigate inefficiencies caused by heading Further details on this approach can be found in section 2.4, which addresses injection heading.
In a gas-lift well experiencing heading, the pressure fluctuations in the flow tube lead to variations in the flowing bottomhole pressure (FBHP) The production rate, determined by the pressure drop from the reservoir to the wellbore, relies on the time-weighted average FBHP, which can be considerably higher than the minimum bottomhole pressure Consequently, a heading gas-lift well yields less production compared to a stable well that maintains a constant minimum FBHP.
— Damage to the well bore.
Unstable operations can result in varying inflow velocities and increased stress on reservoir rock and sand control systems This sand production may damage the wellbore, gas-lift equipment, and surface facilities If left unchecked, excessive sand production can obstruct a producing well, potentially leading to complete well failure.
— Upsets to fluid handling facilities.
Severe heading can lead to significant pressure and rate surges, causing disruptions in gathering, fluid separation, testing, and treatment equipment These disruptions may result in liquid carryovers, gas flaring, meter damage, ruptured burst discs, or the blowing open of thief hatches on tanks.
— Upsets to gas handling facilities.
System upsets caused by severe unstable operation can affect gas compression, dehydration, and distribution systems, causing increased compression and handling costs, gas flaring, and lead to nuisance shutdowns.
— Upsets to other wells on the system.
Heading can occur in a stable well, leading to gas pressure fluctuations These fluctuations can negatively impact other wells within the same distribution system.
— Difficulties in gas and liquid measurement and control.
Most gas measurements utilize differential pressure devices, such as orifice meters, which record static pressure, differential pressure, and occasionally temperature These devices perform optimally under stable conditions However, during well heading, fluctuations in static pressure and rapid variations in differential pressure can significantly reduce measurement accuracy The use of a flow computer with rapid sampling can enhance this accuracy.
Unstable well operation leads to surging production rates which make accurate tubing pressure and well test measurements difficult to obtain.
— Difficulties in analyzing gas-lift performance.
A flowing pressure survey is an effective method for assessing gas-lift performance by measuring production pressures under flowing conditions However, obtaining and analyzing these surveys becomes challenging when a well is heading To ensure meaningful results, it is essential to collect pressure data at each depth throughout the heading cycle.
— Difficulties in controlling and optimizing gas-lift performance.
Continuous gas-lift system design, operation, troubleshooting, and optimization rely on stable operation theories and methods These theories focus on steady state operating conditions, including pressure, rate, and depth, rather than a range of variables However, when wells within a system experience instability, the accuracy of gas-lift models diminishes, making them unreliable for operators seeking guidance.
Types and Causes of Unstable Operation
In continuous gas-lift wells, there are two primary forms of unstable operation: production (tubing) heading and injection (casing) heading It is essential to identify and comprehend these two types of heading, along with their causes and solutions, to effectively differentiate and address them.
In continuous gas-lift, the aim is to inject gas consistently at a steady pressure and rate Conversely, intermittent gas-lift focuses on producing liquid slugs from the well by periodically opening and closing the gas-lift valve and injecting gas into the production stream Despite the well experiencing "slugging," this process is not deemed unstable.
The following practices are recommended for differentiating and addressing types and causes of unstable operation:
— analyze a well’s heading or unstable operating characteristics to determine if the well is experiencing production (tubing) heading, injection (casing) heading, or both tubing and casing heading;
Identify wells with heading issues on a distribution system map to assess whether the problem is isolated or prevalent among multiple wells in a specific area If multiple wells exhibit similar problems, potential causes could include an upstream restriction, instability in the injection system, or a malfunctioning backpressure regulator that manages pressure within the injection system.
— work through the heading analysis procedures to determine the most likely cause(s) of heading;
— take the recommended steps to eliminate or minimize the heading problem Heading is always less efficient than stable operation and severe heading can cause upsets or harm surface facilities.
A stable well maintains a nearly constant tubing-head pressure and flow rate, while an unstable well shows fluctuations in both tubing-head pressure and flow rate over time.
The tubing-head pressure and flow rate can fluctuate, leading to intermittent production with slugs These variations may range from moderate to severe, with tubing-head pressure changing by several hundred psi (kPa) and instantaneous flow rates differing by hundreds or even thousands of barrels per day (m³/day).
Tubing heading can happen independently of casing heading and is often observed in naturally flowing wells This phenomenon typically arises when the production rate is insufficient for the tubing size, leading to excessive liquid accumulation due to low velocity Additionally, production heading may result from inflow from multiple zones, restrictions in surface facilities, or may be exacerbated by existing casing heading issues.
When tubing is under pressure in a well, fluctuations occur at all depths, including at the gas-lift valves The gas flow rate through a valve or orifice depends on the downstream pressure, leading to variations in flow rate as tubing pressure changes, up to the point of critical flow Consequently, as the gas flow rate from the casing annulus to the tubing varies, the casing pressure, known as casing heading, also changes.
Methods to prevent or cure tubing heading include:
— determine if tubing heading is occurring by itself, or in conjunction with casing heading Use pressure transducers to evaluate the fluctuations;
— cure tubing heading by choosing a tubing size that increases mixture velocity An option may be to insert a coiled tubing string inside of the original production tubing string;
To address tubing heading caused by casing heading, reducing the valve or orifice port size can create critical flow, effectively breaking the connection between the two By eliminating fluctuations in casing pressure, the issue of tubing heading can be mitigated or resolved.
Avoid choking the tubing at the surface to address tubing heading, except when necessary to safeguard surface facilities from significant slugging Choking can elevate pressure within the tubing, increase the gas needed for well production, and potentially decrease the overall production rate.
To enhance tubing performance and boost overall production economically, it is advisable to inject additional gas when sufficient supply is available A practical approach, informed by operational experience, suggests increasing the gas injection rate to achieve a velocity of around 6 ft/s (1.83 m/s) above the injection point.
A continuous gas-lift well requires a stable injection pressure and gas injection rate Casing heading refers to fluctuations in injection pressure, which can be linked to changes in gas injection rates Even with a constant flow rate controlled, casing pressure heading may still occur Additionally, tubing heading is frequently influenced or worsened by casing heading.
Casing heading in gas-lift wells occurs when components such as the surface injection control device, unloading gas-lift valves, or operating gas-lift valve are improperly sized or adjusted for steady-state operation The primary culprit is often an oversized operating valve or orifice, which leads to fluctuations in the gas injection rate into the tubing These fluctuations result in variations in tubing flow rate and pressure, exacerbating casing pressure and affecting the inflow and outflow rates of casing gas.
Stable operation occurs when the inflow and outflow rates of gas in the casing annulus are equal A minor imbalance can cause gradual changes in gas volume, while a significant imbalance results in casing heading, as the flow rate through the valve or orifice fluctuates between being greater and lesser than the surface gas injection rate.
Increasing production from a well can complicate operations, especially when the surface control valve is further opened, leading to higher injection rates and casing pressure While this may boost production and reduce tubing heading, it is crucial to monitor casing pressure carefully, as excessive increases could cause one or more unloading valves to reopen.
Casing heading can be exacerbated by under-injection, resulting in self-intermittent operation at the valve Additionally, production pressure operated (PPO) valves are more responsive to fluctuations in tubing pressure Problems in the surface gas distribution system, stemming from heating in nearby wells, as well as issues with gas compression and malfunctions in backpressure control regulators, can also contribute to this phenomenon.
Casing heading can usually be prevented or cured by the following steps.
— Use flowing and static surveys and production tests to find the depth of gas injection, obtain the inflow performance or PI, and create a valid compute model.
Other Problems
If the injection rate is insufficient, it can lead to an increased production gradient, potentially flooding the operating valve This situation may cause a rise in injection pressure, resulting in the subsequent valve opening.
Figure 7—Problem of Under Injection—Causing Operating Valve to Flood
The following practices are recommended for problems with the gas-lift system:
— treat the entire gas-lift system as a “system” consisting of many parts that all must work together, rather than as individual parts which can be considered individually;
— establish and maintain an automatic monitoring system to routinely check and/or calibrate all components of the system;
— establish quality assurance procedures for the assembly, repair, setting, testing, and installation of gas-lift valves and assure that these procedures are followed.
Problems encountered in gas-lift systems are as follows.
Implement preventive maintenance on a regular basis to minimize unscheduled down time Compressor and piping components are mechanical and are subject to malfunction due to wear, corrosion, erosion, or plugging
— Instrument malfunction Maintain and calibrate the pressure, flow, and temperature measurement devices
Sometimes the failure is obvious but often the device appears to be working, but the information is faulty Periodic calibration is required.
— Equipment selection, assembly, or application
Quality assurance is best provided by the following steps.
Establish written standards for gas-lift valve shops regarding assembly, cleaning, repair, re-assembly, pressure charging of bellows, and testing procedures Ensure compliance with available API specifications and recommended practices, particularly API 11V7, which covers the repair, testing, and setting of gas-lift valves Note that this document will be superseded by ISO 17078-2 upon its publication.
— Inspect the valves to insure that proper chokes are installed, if chokes are being used.
Before installing valves in the well, it is essential to test them in the gas-lift shop or on location to ensure they meet design specifications This testing verifies that the valves will open and close as intended, provide the required gas passage rate, and are leak-free, in accordance with API 11V2 standards for gas-lift systems.
Valve Testing and Modeling This document will be replaced by ISO 17078-2 when it is published.
Ensure the installation process is closely monitored to confirm that the valves are installed and adjusted in the proper sequence and at the correct depths It is crucial to communicate any necessary skips of mandrels to the wireline operator to avoid potential issues.
Dehydration is employed to minimize water vapor in gas, preventing hydrate formation and subsequent condensation at low temperatures In a gas-lift system, pressure drops are common, and these are typically accompanied by temperature decreases If conditions are suitable for water condensation, hydrates may develop, leading to gas flow blockages This issue is further discussed in section 3.2.
The effective operation of a gas-lift system relies on accurately modeling various components of the process, including reservoir-to-well inflow, vertical flow within the well, and surface line flow Selecting and utilizing the most appropriate models is essential for a comprehensive understanding of gas-lift operations, as outlined in API 11V8, the Recommended Practice for Gas-lift System Design and Performance.
3 Surface Gas-lift Compression, Dehydration, and Distribution
Purpose
Gas-lift compression and dehydration facilities, along with pipeline distribution networks, are typically already in place Modifications are warranted only if they can lead to increased production or if they can eliminate downtime caused by gas-lift failures.
It is essential to assess the effectiveness of the compression, dehydration, and distribution systems, and any proposed improvements must be justified by their potential to significantly lower operating expenses or enhance production levels.
Compression Facility
The compression facility must reliably supply gas to the gas-lift distribution system at a sufficient rate to maintain a stable system pressure It is essential to monitor this rate and pressure to ensure optimal performance and identify any issues Utilizing a master gas-lift distribution meter, along with a gas flow computer, enables continuous tracking of both the gas input rate and system pressure.
The following practices are recommended for a compression facility:
To ensure a stable gas supply, it is essential to design the gas compression facility for consistent delivery at a steady rate and pressure Implementing a compressor monitoring system is crucial for accurately measuring the flow rate and pressure of gas entering the distribution network In the event of a compressor failure, it is necessary to promptly reduce or shut down certain wells to avoid disruptions in the system.
Set the compressor output pressure regulator to the required level for the gas-lift distribution system, ensuring it is at least 20 psi (137.9 kPa) above the sales line pressure This adjustment will help maintain stability in the sales system and prevent fluctuations from affecting the distribution system, while also allowing excess reservoir gas to flow into the sales line.
To manage excess gas effectively, it is preferable to send it to the sales line or re-inject it into an oil or gas reservoir instead of increasing the distribution system pressure, which could lead to over-lifting of some or all gas-lift wells.
— design the compression facility to deliver sales gas before it enters the gas-lift stage(s) if the sales line pressure is considerably lower than the gas-lift pressure;
— design or configure the compression system to have 10 % to 20 % excess capacity to prevent short-term compressor outages from adversely affecting the gas-lift distribution system;
Implementing a compressor monitoring system is crucial for measuring the flow rate and pressure of gas entering the distribution system Accurate monitoring of these parameters is essential, particularly when the compressor facility is operating at full capacity If a compressor fails, the inflow rate to the system decreases, necessitating an immediate reduction or shutdown of the injection rate into certain wells to avoid system disruptions.
To ensure stable compressor suction pressure, it is essential to provide a make-up or recycled gas supply This is particularly important when the separator gas from the field experiences fluctuations, often caused by heading wells By implementing this make-up supply, the compressor can maintain consistent and reliable operation.
To ensure efficient operation of the compressor facility, it is essential to implement a control system that prevents the delivery of excess gas into the distribution system This system should maintain a constant pressure in the gas-lift delivery system and redirect any surplus gas to the sales line or alternative uses, rather than allowing it to increase the distribution system pressure and over-lift certain wells Establishing a pressure set point for the desired distribution system pressure is crucial, along with measuring the volume of gas sent to the sales line.
— perform routine compressor maintenance and implement a preventive maintenance program to minimize any unscheduled compressor outages;
Coordinate compressor maintenance with well operations to ensure a balance between the gas rate delivered to the distribution system and the total injection rates into the wells served by that system.
To ensure optimal performance, the gas-lift compression facility must be maintained through established troubleshooting and preventive maintenance techniques, aiming for at least 95% operational uptime Frequent disruptions can lead to significant issues within the gas-lift system, resulting in lost production and requiring considerable operator intervention It may take several days for the gas-lift system to stabilize after a compressor upset.
When a compressor experiences downtime or requires maintenance, it is crucial to promptly adjust gas distribution to prevent negative impacts on the system's wells Reducing gas flow to the less productive wells is essential to protect the more productive ones In severe cases, it may be necessary to temporarily shut in the less productive wells during the compressor outage.
A compressor outage in a large gas-lift system necessitates a swift contingency plan In manually operated systems, the most effective strategy is to promptly shut down the least profitable wells Conversely, in systems with computer-controlled distribution and injection, it may be feasible to make optimal adjustments on a well-by-well basis.
Gas compressors play a crucial role in both gas sales and gas-lift distribution It is essential to regulate the pressure to meet the maximum requirements for either application To ensure optimal performance, the pressure regulator must be maintained in good condition and set at least 20 psi (137.9 kPa) above the necessary sales line pressure, preventing any disruptions in the sales system from impacting the distribution system's pressure.
An increase in gas-lift system pressure, originally selected under different field conditions, can enhance the effectiveness of gas-lift operations This adjustment may particularly benefit certain wells.
— are producing with high water cuts;
— are producing from high in the hole because the system pressure is too low to permit working down to the bottom gas-lift valve
If the current system pressure exceeds optimal levels for the well and reservoir conditions, it is essential to reduce the pressure This situation typically arises in wells with low productivity or declining reservoir pressures.
Adjusting system pressure can be straightforward by simply modifying the set point on the sales pressure regulator However, increasing system pressure may necessitate alterations to the compressor cylinders or stages, as well as updates to the distribution system piping, meters, control valves, and gas-lift valves Conversely, to lower the system pressure, it is essential to reset the regulator and potentially adjust the gas-lift valves.
Gas Dehydration Facility
Most gas-lift systems typically utilize dehydrated gas, but some fields employ wet, un-dehydrated gas, which can result in corrosion and hydrate formation This poses a risk of piping blockage if temperatures drop below the hydrate formation threshold for the system's pressure Hydrates, which are solid crystals formed when gas molecules become encased in water molecules, can develop at temperatures as high as 80 °F (26.67 °C) in high-pressure systems.
A significant decrease in temperature often occurs alongside a substantial drop in pressure, a phenomenon known as the Joule-Thomson effect, which can lead to the formation of hydrates in gas The presence of hydrates at chokes or within distribution lines exacerbates pressure drops, intensifying freezing issues This blockage can severely reduce gas flow and may necessitate the shutdown of the well Potential hydrate conditions are illustrated in Figure 8 (courtesy GPSA, Engineering Data Book).
Liquid accumulation in gas-lift distribution systems can lead to measurement and control issues When liquid collects in low spots, it can form slugs that adversely affect gas meters, controllers, and gas-lift valves This slugging can result in inaccurate measurements, ineffective gas control, permanent equipment damage, and significant production challenges in the tubing.
The following practices are recommended for a gas dehydration facility:
To prevent hydrate formation in gas-lift distribution systems, it is essential to dehydrate all incoming gas The primary goal is to reduce the dew point below the lowest anticipated temperature In numerous fields, this dehydration process effectively achieves the desired outcome.
In gas processing, the water content is crucial, with a standard of 7 lb (3.18 kg) of water per million standard cubic feet (28,317 m³) of gas In extremely cold conditions or when CO₂ is present, a drier gas may be required, reducing the guideline to 3 lb (1.36 kg) per million standard cubic feet (28,317 m³) Figure 9 from the GPSA Engineering Data Book illustrates the relationship between water content and dew point temperature, with gas pressure as a variable.
To optimize gas-lift systems, it is essential to prevent significant pressure drops in the surface piping distribution system Utilizing a gas-lift valve instead of an orifice as the operating valve on low productivity index (PI) wells can effectively minimize pressure drop across the surface control choke or control valve, resulting in higher casing pressure.
To optimize gas-lift systems, incorporate liquid traps at low points to prevent liquid accumulation, particularly before gas flowrate meters or control devices It is essential to install blow down valves in these traps for the periodic removal of accumulated liquid Additionally, large piping distribution systems, especially in offshore environments, should be equipped with pig launchers and receivers to facilitate the removal of liquid and debris through regular pigging operations.
— if the presence of liquid cannot be avoided, periodically purge the distribution system to remove accumulated liquid Purge orifice meter pressure and differential pressure taps periodically;
To ensure accurate measurements, utilize seal pots (liquid traps) on orifice meter pressure and differential pressure taps, and perform regular purging Additionally, position the meter recorders or transmitters at a higher elevation above the orifice tube, ensuring that the connecting instrument piping is free of traps.
To prevent temporary freezing issues, it is advisable to use methanol, which acts as a hydrate point depressant and effectively lowers the dew point Additionally, insulating control valves or chokes where significant pressure drops may happen is crucial The most effective strategy is to proactively address these challenges through efficient dehydration methods, thereby minimizing potential costs and complications.
— use a heater (line, gas, or catalytic) as an alternative to avoid hydrate formation if effective dehydration is not an option.
Gas-lift Distribution System
An effective distribution system is characterized by a large volume, which stabilizes pressure fluctuations This design minimizes the impact of minor variations in inlet or outlet rates, preventing rapid pressure changes across the system.
Figure 9—Water Content vs Temperature and Pressure
The following practices are recommended for an unstable gas-lift distribution system:
— use a “finger” distribution system, Figure 10, with each well served by an individual injection line from a manifold;
— measure and control the injection rate to each well at the manifold Measure the injection gas pressure at the wellhead just before the gas enters the casing annulus;
Using a manifold allows for the measurement and control of injection rates to each well, leading to cost savings However, it is advisable to measure injection pressure at the wellhead, just before the gas enters the casing annulus, rather than at the manifold, especially if the individual injection lines are long.
In situations where a "finger" system is impractical, it is advisable to implement a "looped" system, as illustrated in Figure 11 This approach enhances the distribution system's volume, effectively reducing disturbances caused by minor fluctuations in inlet or outlet rates.
— use larger diameter distribution piping if combining continuous and intermittent gas-lift wells on the same system
If possible, schedule the intermittent cycles to minimize upsets, which could occur due to concurrent, uncoordinated injection cycles;
To optimize gas-lift operations, it is crucial to avoid mixing continuous and intermittent gas-lift wells within the same system If integration is unavoidable, ensure that intermittent controllers are programmed to activate at staggered times or implement a centralized control system to automatically schedule intermittent cycles This approach helps minimize disruptions caused by simultaneous, uncoordinated injection cycles.
Pressure pulsations can hinder production when the distribution system's piping is undersized To enhance system volume capacity, consider connecting the annulus of a temporarily abandoned well It's crucial to verify the integrity of the casing and wellhead, and install a pressure transducer on the casing head Ensure there are no restrictions, such as chokes or control valves, between the distribution system and the storage annulus This increased volume will help mitigate pressure fluctuations and provide a convenient gas storage solution during shutdowns, such as for hurricanes Retaining high-pressure gas in the distribution system can facilitate the return to production, as there may be inadequate gas supply to restart operations after a shutdown.
The optimal "finger" configuration featuring a large distribution pipeline effectively reduces interference between wells by isolating them through the manifold It is essential to monitor the pressure, temperature, and gas flow rate entering the manifold from the distribution system, as this data aids in troubleshooting issues within the overall distribution system and assessing the gas availability for the connected wells Additionally, measuring the injection and production pressures at the wellhead is crucial for efficient operation.
In systems utilizing a "series" or "looped" configuration, interference between wells can occur; however, this issue can be alleviated by increasing the system's volume through larger pipe diameters Additionally, employing the annuli of non-producing wells or implementing parallel looped lines can further assist in mitigating interference It is essential to measure gas flow rate, casing pressure, and tubing pressure data directly at the well site for optimal performance.
In continuous gas-lift distribution systems, particularly in series or looped configurations, it is crucial to prevent pressure fluctuations and rate surges, as these can destabilize wells and cause cascading instability in nearby wells Addressing heading problems is essential, and the use of intermittent gas-lift should be avoided If necessary, intermittent gas-lift for lower rate wells should be centrally scheduled and controlled to reduce interference and fluctuations Ideally, intermittent wells should be isolated from continuous gas-lift wells within a separate section of the distribution system.
Measuring and recording pressure and flow rates at critical points in distribution systems is essential for effective troubleshooting of system issues and the wells connected to specific branches However, achieving accurate gas measurements can be challenging in systems experiencing fluctuating pressures.
4 Gas Injection Metering and Control
Purpose
Gas-lift systems necessitate precise measurement and control points for the gas injected into each well, enabling operators to manage system performance effectively and identify under-performing wells Accurate and consistent gas-lift measurement and control are essential for optimal operation.
Gas Metering
Gas injection measurement plays a crucial role in optimizing and troubleshooting gas-lift systems Accurately measuring the continuous injection pressure and rate of a single-phase fluid surpasses the reliability of separator gas measurements during well tests, which can be affected by slugging and liquid-saturated gas Additional variables that can be monitored at the wellhead include injection (casing-head) pressure, injection gas temperature, producing (tubing-head) pressure, producing temperature, and, in certain instances, production rate.
The following practices are recommended for gas metering:
— measure the gas injection pressure and rate for each well;
— use a properly installed, properly ranged, well-maintained, accurately calibrated flow rate measurement device;
— use flow computers to obtain improved accuracy for well analysis Use multi-range differential pressure transmitters that extend the maximum and minimum rate capability of the orifice meter;
— use a computer automation system to gather information;
— pay special attention to obtaining accurate gas injection pressure and rate information during each well test.
The placement of the meter is determined by the distribution system type, with a "finger" system typically having the meter located at the manifold, while a "series" or "looped" system features a meter at each well To ensure accurate measurements, rates should be recorded upstream of each well's control valve, allowing for the assessment of static pressure in the upstream distribution system Additionally, recording temperature can enhance measurement precision, and the collected data is essential for both rate measurement and analyzing pressure fluctuations within the distribution system.
The orifice meter is the preferred instrument for measuring gas injection in the oil field, effectively functioning when paired with a flow computer or a calibrated chart recorder.
An orifice meter, flow computer, or chart recorder should meet the following criteria.
— applicable API, GPA, or ASME standards should be followed;
— the orifice meter should be properly located with respect to chokes, control valves, pipe, and bends;
— the orifice meter instrument tubing to the pressure transducers or chart recorder should avoid low spots that can collect condensed moisture Seal pots can be used to trap condensation;
— chart recorders should be equipped with a three-way or five-way manifold for easy and safe blow down and purging The tubes should be routinely purged;
To accurately measure the expected gas flow rate, it is essential to properly size the orifice meter tube and orifice plate The differential pressure should ideally be maintained in the midrange of the computer or recorder chart, avoiding extremes at the bottom or top of the scale Additionally, employing multi-range transmitters for flow computers is recommended for optimal performance.
Orifice plates must remain unpainted and free from dirt, scale, scars, nicks, wear, bends, or any damage To avoid corrosion or damage, it is essential to store orifice plates properly when they are not in use.
Routine calibration of chart recorders is essential, along with regular checks of the recorder's pens to ensure proper inking For well testing, the recorder should feature a 24-hour clock drive, with charts replaced before and after testing While 8-day clocks suffice for routine surveillance, they may present challenges in reading measurements accurately.
For effective gas-lift surveillance, utilize the injection gas rate from the flow computer or chart alongside a well test The formation gas/oil ratio is calculated by subtracting the gas injected during the well test from the total gas recovered, which includes both produced and injected gas Accurate readings of both the injection gas rate and total gas recovered are essential for determining the reservoir gas production rate.
Operators can utilize recorders featuring either linear charts or L-10 (square root) charts The L-10 charts offer the benefit of directly obtaining a 100-inch (256-cm) water column differential pressure from the chart reading However, calculating static pressure requires equations to convert from square root to linear For added convenience, some charts incorporate both scales.
Microprocessor-based gas measurement devices not only provide accurate gas measurements, particularly for heading wells, but also facilitate gas flow rate control These flow computers outperform traditional chart recorders by requiring less maintenance, calibration, and reading time Additionally, they enable remote communication with a central computer for the display, utilization, and storage of pressure, rate, and volume data.
Other metering alternatives are available, but orifice meters and flow computers are proven methods Other methods include flow nozzles, Venturi meters, vortex shedding meters, and turbine meters.