Halulindo

The guidelines in this section are adapted primarily from API RP 11 V5 (1999), Recommended Practice for Operations, Maintenance and Troubleshooting of Gas Lift Installations.

Initial Unloading

The first step in bringing a well on production after gas lift valves have been installed is to unload the fluids from the wellbore and obtain a stabilized production rate. Normally, a well placed on continuous gas lift is unloaded continuously, and a well placed on intermittent gas lift is unloaded intermittently. Primary considerations in unloading include avoiding excessive pressures that could damage the valves, and using clean, filtered workover fluids to avoid plugging or abrasion of the valves.

Prior to unloading, a two-pen pressure recorder should be installed at the surface to monitor both the gas injection pressure and the production (tubing) pressure. These pressures should be measured as close to the wellhead as practical. In any case, the gas injection pressure should be measured downstream of the injection choke, and the production pressure should be measured upstream of any flowline choke that is present. The wellhead pressure should be bled down to the pressure of the downstream separator, and the flowline choke, if present, should be either fully open or removed.

Continuous Gas Lift Wells

With continuous gas lift, the unloading process begins when gas is injected slowly into the annulus, probably through a choke located at the surface. Pressure is incrementally raised by approximately 50 psi every eight to ten minutes until it reaches about 400 psi, and 100 psi every eight to ten minutes thereafter. The kill fluid is displaced through the standing valve, up the tubing and to the surface into a disposal tank, until gas starts coming around the first valve or oil appears in the produced fluid. A steady stream of fluid will be then unloaded. If these fluids are directed into a separator, it is important to keep the backpressure on the well as low as possible. As gas is continuously injected into the annulus, a gradual increase in casing pressure will be required to keep fluids flowing from the tubing string.

Valve 1, the uppermost valve, is the first valve to be uncovered; gas first enters the tubing string at this point. This is noted at the surface by an immediate increase in the velocity of the fluid stream coming out of the tubing. A mixture of gas and liquid is soon produced at the surface, and the casing pressure levels off at the surface operating pressure of Valve 1. As gas continues to enter the annulus, the liquid column in the annulus is lowered until Valve 2 is uncovered. As soon as this valve is uncovered, gas flows through it and enters the tubing. Casing pressure then drops to the surface operating pressure of this valve. At about the same time, pressure in the annulus opposite Valve 1 should have been reduced to a level low enough to cause that valve to close.

Unloading continues from valve to valve until the deepest operating valve is uncovered. At this point, the bottomhole pressure has been reduced to a level that allows the formation fluid to move into the tubing, and the volume of gas injected through the operating valve is sufficient to lift the production under design conditions.

Intermittent Gas Lift Wells

With intermittent gas lift, fluid is unloaded at the surface in the form of piston-like slugs. The unloading process is the same as that for continuous flow until the uppermost valve (Valve 1) is uncovered. At that point, the well is placed on intermittent control for unloading. This is accomplished with a choke or a time-cycle controller at the surface so that the well is alternately produced and shut-in. During this period, the fluid in the annular space will continue to be U-tubed into the tubing and will be produced as slugs. A good cycle for unloading is obtained with 2 to 4 minutes of gas injection every 20 to 30 minutes. This allows ample time for stabilization to take place between slugs.

When the well is unloaded down to the operating valve, the choke size or cycle time should be adjusted to suit the well’s production characteristics. Thus the unloading operation may start with a high number of cycles per day and then, in response to the well’s production behavior, the number of cycles will be adjusted downward as fewer cycles will be needed to maintain optimum production rates. If the fluid production rate begins to fall off, then the number of daily cycles is too low for optimal production. With this information, it is possible to make further refinements to the process by reducing the duration of gas injection during each cycle. The objective is to maximize production and minimize the gas volume required. A very useful monitoring procedure involves simultaneously recording the shapes of the tubing and casing pressures curves. Adjustments are made on the basis of the shapes of these two curves.

System Adjustments

Once a well is unloaded, the next step is to optimize its production rate and gas usage. This will require some adjustment of its operating parameters. For detailed procedures, refer to API RP 11V5 (1999).

In a continuous gas lift installation, adjustments are generally made using an adjustable choke to control the rate of gas injection (a positive choke could also be used, but this would require interrupting gas injection to change the choke size). To prevent freezing, the gas system may be equipped with a dehydrator, gas heater or heat exchanger, or methanol may be injected upstream of the choke. To adjust the gas injection rate, the choke is initially set at a diameter that is larger than required for the design rate. The diameter is reduced incrementally until the production rate begins to drop, and then readjusted to establish the optimal production rate.

Similar types of adjustments are made for intermittent gas lift installations that employ time cycle control: the controller is initially set for a duration that will exceed the design gas injection requirements, and then the number of cycles per day is reduced until the well can no longer produce at its desired rate. The controller is then reset in steps until the optimal production and gas injection rates are established. For intermittent wells operating on choke control, the choke is initially sized for the design production rate, and then adjusted in the same type of trial-and-error manner.

Gas Lift System Monitoring

Successful gas lift performance depends largely on the efforts of field personnel. A gas lift installation requires close supervision during the unloading process, and when injection gas is adjusted and regulated.

A common practice is to analyze the system only when a problem arises. A better approach is to analyze each well while it is operating satisfactorily to determine if the installation has been properly designed. This provides a baseline measure of performance for reference in the event of trouble, and helps to indicate needed design changes. It is important to analyze this baseline information before planning well servicing or workover operations—otherwise, the operator will not know what changes are needed.

Diagnostic tools for monitoring and troubleshooting gas lift wells include:

Two-pen pressure recorder charts and calibrated pressure gauges installed at the well
Acoustical and production logging surveys
Fluid level determinations using wireline


API RP 11V5 (1999) describes these tools and their applications in detail.

Remote Monitoring

Gas lift wells are a common area of application for remote monitoring and control techniques. These systems can measure the performance of a single well or an entire field using sensors and data transmitting devices that alert field personnel to changes in well performance. By comparing performance parameters over time, the operator can analyze well stability, allocate lift gas injection, and optimize the operation of the entire field. This capability leads to improved efficiency, better field operations management, and increased profitability.

A significant feature of monitoring systems is their ability to remotely control gas injection and change well settings using two-way control devices. Continuous monitoring and comparison of parameters such as injection pressure, wellhead pressure, and flow rate lets the operator identify potential problems and take preventive and corrective action from a central location. In many cases, the operator is notified automatically when sensors detect significant changes to key parameters.

Primary components of remote monitoring systems include:

Downhole Pressure & Temperature Sensors
Sensor Data Process System
Well Controller
Remote Terminal Unit (RTU)


The downhole pressure and temperature sensors communicate via a system controller to adjust gas injection through the sensor data process system. This allows the operator to control the well or the field based on changing surface or downhole conditions.

A remote terminal unit (RTU) can transmit data continuously or store well performance data for later transmission and analysis. The RTU is a two-way system, thus allowing the operator to communicate back to the well.

The monitoring and communication equipment is powered by solar cells, which are backed up by a battery system to ensure a constant power supply.

Through monitoring of gas lift injection and production systems, field efficiency can be improved and future gas lift valve design, valve placement and unloading programs can be designed on the basis of actual field operating experience.

Source : www.reggieoilservices.com