1. Communication between Casing & Tubing
Causes Cures
A. Valve Stuck Open A. Rock the well, flush the valve
B. Packer leaking B. Reset packer
C. Tubing Leak C. Tubing patch / re-run new tubing
2. Injection Pressure Increases
Causes Cures
A. Upper valve is operating valve A. Adjust injection gas Pressure B. Valve plugged B. Valve needs to be replaced
C. Temperature rise affecting valves C. Lower TRO pressure of valve
3. High Back Pressure at Wellhead
Causes Cures
A. Plugged flow line A. Needs treatment accordingly B. Flow line size too small B. Loop flow line or larger line
C. Well using too much gas
4.5 Troubleshooting: Diagnostic Tools
4.5.1 Calculations: One method of checking gas-lift performance is by calculating the “tubing load required” (TLR) pressures for each valve. This can be accomplished by calculating surface closing pressures or by comparing the valve opening pressures with the opening forces that exist at each valve downhole based on the operating tubing, and casing pressures, temperatures, etc. Although this method may not be as accurate as a flowing pressure survey because of inaccuracies in the data used, it can still be a valuable tool in highgrading the well selection for more expensive diagnostic methods. Weatherford’s VALCAL gas-lift design software is available for this type of diagnostics.
4.5.2 Well-Sounding Devices: The fluid level in the annulus of a gas-lift well will sometimes give an indication of the depth of lift. This method involves imploding or exploding a gas charge at the surface and uses the principle of sound waves to determine the depth of the fluid level in the annulus. Acoustic devices are fairly economical compared to flowing-pressure surveys. It should be noted that for wells with packers, it is possible for the well to have lifted down to a deeper valve while unloading, then return to operation at a valve up the hole. The resulting fluid level in the annulus will be below the actual point of operation.
4.5.3 Tagging Fluid Level: Tagging the fluid level in a well with wireline tools can sometimes give an estimation of the operating valve subject to several limitations. Fluid feed- in will often raise the fluid level before the wireline tools can be deployed down the hole. In addition, fluid fallback will always occur after the lift gas has been shut off. Both of these factors will cause the observed fluid level to be above the operating valve. Care should be taken to ensure that the input gas valve was closed before closing the wing valve, or the gas pressure will drive the fluid back down the ole and below the point of operation. This is
certainly a questionable method.
4.5.4 Two Pen Recorder:
Fig. 4.4 - Two Pen Recorder Installed on Well Head
4.5.5. Flowing Pressure Survey In this type of survey, an electronic pressure gauge or bomb is run in the well under flowing conditions. These recording instruments can also measure temperature, and both ambient and “quick -response” models are available.Under flowing conditions, a no-blow tool is run with the tools, which prevents the tools from being blown up the hole. The no-blow tool is equipped with dogs, or slips, that are activated by sudden movements up the hole. The bomb is stopped at each gas-lift valve for a period of time,
recording the pressures at each valve. From this information, the exact point of operation can be determined, as well as the actual flowing bottomhole pressure (BHP). This type of survey is the most accurate way to determine the performance of a gas-lift well, provided that an accurate well test is run in conjunction with the survey. The following procedure explains the process in detail.
Procedure for Running a Flowing BHP Test When the Well Is Equipped with Gas-Lift Valves
a. Continuous-Flow Wells
1. Install a crown valve on the well, if necessary, and flow the well to the test separator for 24 hours so that a stabilized production rate is known. Test facilities should duplicate normal production facilities as nearly as possible.
2. Put the well on test before running the BHP. The test is to be run for a minimum of 6 hours. A gas and fluid test, two-pen recorder chart, and separator chart should be sent in with the pressure traverse.
3. A pressure bomb must be equipped with one, or preferably two, no-blow tools. Use a small- diameter bomb.
4. Install a lubricator and pressure-recording bomb. Make the first stop in the lubricator to record wellhead pressure. Run the bomb, making stops 15 ft below each gas-lift valve for 3 minutes. Do not shut in the well while rigging up or recording flowing pressures in tubing.
5. Leave the bomb on bottom for at least 30 minutes, preferably at the same depth that the last static BHP was taken.
6. The casing pressure should be taken with a deadweight tester or “master test” gauge, or a recently calibrated two-pen recorder.
b. Intermittent-Flow Wells
1. Install a crown valve on the well if necessary, and flow the well to the test separator for 24 hours so that a stabilized production rate is known. Test facilities should duplicate, as nearly as possible, normal production facilities.
2. Put the well on test before running the BHP. The test is to be run for a minimum of 6 hours. Test information, two-pen recorder charts, and separator chart should be sent in with the pressure traverse.
3. A pressure bomb must be equipped with one, or preferably two, no-blow tools. Use a small- diameter bomb.
4. Install a lubricator and pressure recording bomb. Let the well cycle one time with the bomb, just below the lubricator, to record the wellhead pressure and to ensure that the no-blow tools are working. Rub the bomb, making stops 15 ft below each gas-lift valve. Be sure to record a maximum and minimum pressure at each gas-lift valve. Do not shut in the well while rigging up or recording flowing pressures in the tubing.
5. Leave the bomb on bottom for at least two complete intermitting cycles.
6. High and low tubing and casing pressures should be checked with a deadweight tester or “master test” gauge, or a recently calibrated two-pen recorder.
Where to Install a Two-Pen Recorder Connect Casing Pen Line
• At the well, not at compressor or gas distribution header.
• Downstream of input choke so that the true surface casing pressure is recorded.
Connect Tubing Pen Line
• At the well, not the battery, separator, or production header.
• Upstream of choke body or other restrictions. Even with no choke bean,a less-than-full opening found in most of the chokes.