API RP 11V8-2003 pdf download.Recommended Practice for Gas Lift System Design and Performance Prediction.
1 Overview of a Gas Lift System This section provides a broad overview of the various com- ponents of a gas lift system and how these components inter- act with one another. 1.1 MAJOR COMPONENTS OF A GAS LIFT SYSTEM The components of a gas lift system can be grouped as follows: a. Gas compression and distribution system. b. Subsurface equipment. c. Gas and liquid gathering system. A. Gas Compression and Distribution System A typical gas compression and distribution system is com- posed of a compression and dehydration plant, manifolds, gas lines, meters, and rate control devices as depicted in Figure 1- 1. The compressor station receives gas from the low pressure separator and gathering system, or from gas wells, or from the sales pipeline, and compresses it to a pressure suitable for gas lift operations. The compressor discharge pressure typi- cally ranges from 800 psig – 2000 psig, although other pres- Glycol dehydrator Surplus gas to sales sures are used as needed, based on reservoir pressure, well productivity (PI), and gas lift valve constraints. The amount of gas required depends on a number of criteria: · Number of wells and the depth of the injection point. · Amount of oil and water to be produced and the water fraction. · Amount of formation gas produced. · Reservoir pressure. Compressor options are based on the required gas rate: 1. Small reciprocating units can compress a few million standard cubic ft per day—sufficient for a small field with a few wells. 2. Large reciprocating units can compress from a few million to a hundred million standard cubic ft per day—for large on-shore fields with numerous wells. 3. Centrifugal compressors can compress from a few mil- lion to more than a hundred million standard cubic ft per day—for numerous wells in large oil fields, espe- cially offshore. Gas lift uses the same surface facilities that process formation gas, since most fields require compression, dehydration,
Gas lift valve installation and retrieval methods are: · Conventional valves and mandrels installed/retrieved 3 with the tubing. · Wireline installed/retrieved valves set inside the pocket of a side-pocket mandrel in the tubing string. · Special valves and mandrels installed/retrieved with coiled tubing. P b P b A b F c Important, fundamental concepts about valves, Figure 1-3, are: · Valves control the point of entry of the compressed gas into the production string and act as a pressure A b P g F o P g regulator. · Valves have cross-sectional areas at the bellows ( A b ) and at the stem/port ( A p ) that pressure acts on: – nitrogen pressure ( P b ) and/or a spring forces the stem/ball to close on the port seat, – injection gas ( P g ) and fluid production ( P f ) pres- sures provide the counter forces that act to open the valve. A p P f Pictorial A p F o P f Schematic · Valve port size may be a constraint to the maximum amount of injected gas, but the optimum gas rate is adjusted with the surface injection choke or controller (a choke in the valve can also be used). · A reverse flow check valve, mounted below the port of the valve, prevents flow from the production fluid con- duit back into the gas column (not shown). An orifice can be used in lieu of a valve at the expected depth of injection. The orifice consists of the orifice (port) and the reverse flow check, but does not have a bellows and stem, so it is not a valve that can open or close. Usually, the gas lift valve allows the injection gas to flow from the tubing-casing annular space into the production tub- ing. But alternatively, a gas lift valve can be installed to allow the gas to flow from the tubing into the annular space where it mixes with the production fluids coming from the reservoir. This is done when the gas and oil flow rates are high and require the annular area to minimize pressure loss.