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Casing-annulus-flow installation design
The design calculations for an annular-flow installation are similar to those for a continuous-flow installation through the tubing. Intermittent gas lift is not recommended for annular flow. Because the gross liquid production is generally thousands of barrels per day, selecting valve port inside diameter (ID) sizes for adequate gas passage is very important for annular-flow installations. Actual gas lift valve performance, based on port ID, maximum linear stem travel, and bellows-assembly load rate, is an important factor in the design calculations for annular-flow installations because of the high injection-gas requirements. The increase in the injection-gas pressure to overcome the bellows-assembly load rate and to attain the needed equivalent port area for a required injection-gas throughput should be considered.
Installation design
Selection of the proper size of gas-injection tubing string that will deliver the required daily injection-gas requirement for unloading and operating is absolutely essential. An initial assumption can be an injection-gas tubing size that will deliver the maximum daily injection-gas requirement with no pressure loss (i.e., the increase in the injection-gas pressure with depth, as a result of gas-column density, is offset by the flowing frictional pressure loss). This should be the smallest nominal tubing size considered for the injection-gas string. Charts for static injection-gas pressure at depth cannot be used for the valve spacing calculations.
The Cullender and Smith[1] correlation is recommended for calculating the pressure loss in the injection-gas tubing string. This method for calculating the flowing injection-gas pressure at depth was derived for a producing gas well and not for gas injection. The only difference in the calculations is the friction term for gas being injected rather than being produced. The sign for the friction term changes (i.e., the friction term becomes negative in the Cullender and Smith equation for gas injection).
Wireline-retrievable gas lift valve mandrels that accommodate standard injection-pressure-operated valves for annular flow are available (Fig. 1). When these mandrels are used, the valves are run and set in the pocket in exactly the same manner as for tubular flow. However, the mandrel configuration is such that the injection gas enters the side of the pocket from inside the tubing. This allows injection gas to pass through the valve and exit the pocket into the casing annulus rather than into the tubing. Annular-flow mandrels should be used for annular flow wherever possible because they allow full gas passage through the valve without the restriction imposed by cross-over seats. Also, gas is injected from the bottom rather than the side of the mandrel. This provides a much safer installation from an erosion standpoint than the installation using valves with crossover seats in which gas is injected from the side of the pocket into the wall of the casing.
Fig. 1-The mandrel pocket configuration differs for annular flow because injection gas enters the pocket from the tubing rather than the casing.
Where mandrels for tubing flow are already installed and are not feasible to replace, valves with crossover seats must be installed. In such installations, the check disk in the reverse-flow checks valve seats in the opposite direction for casing flow as compared to a tubing flow installation and allows gas passage from the injection-gas tubing to the casing annulus. In the wireline-retrievable valve tubing flow series mandrel, the valve for casing flow is similar to a production-pressure-operated valve, except the integral check valve is reversed for injection-gas flow from tubing to casing.
Because nitrogen-charged bellows gas lift valves have a lower bellows-assembly load rate than a spring-loaded valve, bellows-charged valves are recommended for high injection-gas volumetric throughput, as required for most annular-flow installations. Fortunately, the valve temperature at depth is not difficult to predict accurately in high-volume wells. The flowing surface temperature is near the bottomhole flowing temperature; therefore, the operating temperature of all valves in a high-volume, annular-flow gas lift installation is approximately the same. An important caution is to never use the surface injection-gas temperature to estimate the valve temperature at depth. The injection gas will begin to approach the flowing-fluid temperature within a few hundred feet of the surface. The flowing wellhead temperature of the fluid production should be used to establish the unloading valve temperatures at depth. This same consideration is applicable to the Cullender and Smith injection-gas pressure-at-depth calculations.
References
- ↑ Cullender, M.H. and Smith, R.V. 1956. Practical Solution of Gas-Flow Equations for Wells and Pipelines with Large Temperature Gradients. Petroleum Transactions, AIME 207: 281-287.
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See also
Gas lift installation design methods
Intermittent-flow gas lift installation design