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Unconventional production patterns in the Permian Basin are leading producers to replace electrical submersible pumps (ESPs) with gas lift, which had been little used there. When a gas lift system starts performing poorly, there is a good chance no one will notice. It is not an event that demands attention like a broken pump. A gas lift system will continue injecting gas into wells and oil will continue to come out. Just not as much oil as there could be.
In designing a UBD circulation system, the bottomhole pressure must be maintained below the reservoir pressure. The surface separation system must have sufficient capacity to handle the flow rates and pressures expected while drilling. The surface separation system must be capable of handling sudden productivity increases from the well from fractures or flush zones and retain the ability to "choke" back production if well outflow is more than what can be handled safely by the surface separation equipment. The separation system must also be able to work within the design parameters of the well. The BHP must be less than the static reservoir pressure under static and dynamic conditions to enable reservoir fluid inflow into the wellbore.
In overbalanced drillng (OBD), a mud weight is selected that provides a hydrostatic pressure of 200 to 1,000 psi above the reservoir pressure. In UBD, we select a fluid that provides a hydrostatic pressure of around 200 psi below the initial reservoir pressure. This provides a good starting point for the selection of a fluid system. During the feasibility study, this drawdown is normally further refined, depending on the expected reservoir inflow and other drilling parameters. This first look provides an indication if the fluid should be foam or gasified or if the well is drilling with a single-phase fluid (Figure 1).
The advent of the unbalanced, single-element, bellows-charged gas lift valve revolutionized gas lift application and installation design methods. The following topic describes the various types of gas lift valves and crossover seats currently used in the industry. The unbalanced, single-element gas lift valve is essentially an unbalanced pressure regulator. The closing force for a gas lift valve can be a gas pressure charge in the bellows exerted over the effective bellows area or a spring force, or a combination of both. The closing force for the regulator or gas lift valve can be adjusted to maintain a desired backpressure for injection-pressure operation. The regulator or valve remains closed until this set closing force is exceeded. Generally, the major initial opening force for a gas lift valve is the pressure exerted over the effective bellows area minus the port area, and the lesser opening force is the pressure acting over the port area. In like manner, the major opening pressure for a pressure regulator is applied over an area equal to the diaphragm area minus the port area.
Valves with small production-pressure factors, Fp, are recommended for the decreasing injection-gas pressure installation design method. Valves with a small Fp (under 0.2) are sensitive primarily to a change in the injection-gas pressure. A decrease in the surface operating injection-gas pressure for each lower gas lift valve is essential to ensure the closure of upper unloading valves after gas injection has been established through a lower operating valve. This design is particularly applicable when the available injection-gas pressure is high relative to the required depth of lift and an additional incremental decrease in injection-gas pressure can be added between valves. If gas lift valves with large ports are required to pass sufficient gas rates for unloading and lifting a well, the design that incorporates valve performance should be used. Generally, if the operating valve is not near the packer, the calculated point of gas injection will be bracketed by installing at least one valve below the calculated operating valve depth in the event there is a slight error in the well information or a change in well conditions. This installation design method (following API) is based on all gas lift valves having the same port size and a constant decrease in the operating injection-gas pressure for each succeeding lower gas lift valve. The gas lift valve selection must be based on a port size that allows the injection-gas throughput required for unloading and gas lifting the well. This installation design method is recommended for gas lift valves with a small production-pressure factor. When the ratio of the port area to the bellows area is low, the decrease in the injection-gas pressure between gas lift valves, based on the additional tubing-effect pressure for the top valve, is not excessive.
Continuous-flow gas lift is analogous to natural flow, but there are generally two distinct flowing-pressure traverses. The traverse below the point of gas injection includes only formation gas; whereas, the traverse above the point of gas injection includes both the formation and injection gases. These two distinct flowing-pressure traverses and their corresponding gas/liquid ratios (GLR) are illustrated in Figure 1. There are numerous gas lift installation design methods offered in the literature. Several installation designs require unique valve construction or gas lift-valve injection-gas throughput performance. The API design can be used on the majority of wells in the US.
The following topic describes Gas distribution and control, Gas compression and dehydration and Gas surface facilities. Figs. 1 and 2 show the amount of injection gas and compression brake horsepower per well, respectively, required to obtain identical producing rates using several different surface injection-gas pressures. As expected, compression horsepower decreases as injection-gas pressure increases for a given daily liquid rate, until the injection-gas pressure reaches maximum injection depth. An injection-gas pressure greater than that required to inject at maximum depth requires additional compression without additional production. In the example shown in Figs. 1 and 2, a significant decrease in horsepower requirements is possible by employing an injection-gas pressure of 2,000 psig (ANSI Class 900 pipe) rather than one of 1,440 psig (ANSI Class 600 pipe) or lower.
Downhole gas lift equipment consists mainly of the gas lift valves and the mandrels in which the valves are placed. The compressor horsepower requirements are considered in analyzing the gas lift system design. Please look at the page of gas lift equipment and facilities for more details. The early gas lift valves were the conventional tubing-retrievable type, in which the tubing mandrel that held the gas lift valve and reverse check valve was part of the tubing string. It was necessary to pull the tubing to replace a conventional gas lift valve.
Hassi Messaoud is a mature oil field with more than 1,100 production wells. Approximately half of the wells are natural flow and the other half use continuous gas lift (CGL) with concentric (CCE) strings. The first subsea multiphase boosting system was installed in 1994. Since then, it has grown into a technology with a global track record. Using maglev technology, a new artificial lift system seeks to boost production output by sucking down reservoir pressure from inside the wellbore and from inside the reservoir.
This course is an in-depth look at artificial lift, specifically for wells using continuous-flow gas lift or electrical submersible pumps (ESPs). The course can also be modified for a 5-day exclusive ESP training program with hands-on problem solving using SubPUMP software. In either case, there are plenty of class problems to solve in the workshops, and problem scenarios from the attendees are always welcome. The instructor for this course draws on 40 years of experience in the business. By the end of the week, you’ll have a firm grasp of ESP and gas lift systems.