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API RP 11V8-2003 pdf free download

API RP 11V8-2003 pdf free download.Recommended Practice for Gas Lift System Design and Performance Prediction.
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. Manifold connected flowlines—in large fields where the wellheads are distant from the separation plant, gathering manifolds can minimize total pipeline length. The wellhead to manifold connection is sized as stated above. From the manifold, usually two flow lines con- nect with the flow station. One is the production pipe- line, used to transport the commingled flow from all the wells (except for the one being tested), and is sized for total flow including future water increases plus lift gas. The other is a smaller diameter test line and is used to connect only one of the wells to the test separator where its fluid and gas production is measured. · A test separator located at the manifold is an option to avoid the need for the small test line and associated purging methods for long test lines. From the separator flow station, the low-pressure gas is returned to the compression plant to complete the cycle.
Gas compression and distribution must provide a steady, constant pressure supply of dehydrated gas at an adequate rate for all wells served: · Low gas pressure causes the point of gas injection to be too shallow. · High gas pressure deepens the point of lift when the unloading valve pressures are appropriately set. · Gas rate, liquid rate, and the mixture density control the flowing bottomhole pressure. · Injection gas rate must be matched to the liquid rate and tubing size because: – inadequate gas will not sufficiently reduce density, – the resulting low fluid velocity permits excessive liquid holdup, – excessive gas causes friction pressure loss to increase. · Injection gas rate is adjusted with a surface choke or gas flow rate control valve. Gas and liquid gathering components must be properly sized to allow maximum production: · Well production is limited by the imposed system back- pressure created from: – high separation pressure, – a flow line with a small diameter, – a long flow line with diameter too small for the dis- tance. · Pipe sizing should be based on realistic flow rates since: – excessively large diameter can cause severe slug- ging, – too small of a diameter results in excessive friction losses. The subsurface gas lift design is used to achieve the objec- tive of reduced density and low flowing bottomhole pressure

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