This will provide a quick understanding of general requirements typically found on Floating Production Storage and Offloading (FPSO) and Tension Leg Wellhead Platform (TLWP) concerning gas lift and injection systems.
Gas from the export compression should be exported to the TLWP via a Fluid Transfer Lines (FTL) for use as lift gas for production wells and for injection into convertible production wells.
Provisions should be made for pressurizing a depressurized gas FTL from the running compression (backpressure control or small bore bypass with globe valve).
Facilities should be provided on the topsides for de-pressuring the gas lift/injection FTL to the FPSO flare system, at a maximum depressurisation flow.
The export compression system should deliver lift and injection gas to the TLWP FTL.
The gas system must ensure all associated gas can be processed for reinjection or for use as lift gas.
Facilities must be provided to allow gas import from the gas injection wells to:
- Provide a means of using lift gas to start production (sufficient to allow kick off of production wells after a full process shutdown).
- Provide facility fuel gas requirements when the process trains are shutdown, during start-up activities and in late life when associated gas rates are insufficient to meet fuel gas demand.
- Provide for future gas export.
- Allow dewatering of the gas injection subsea flowline during commissioning.
The gas systems must be designed to:
- Operate stably during slugging events.
- Be robust for the full range of fluid compositions described according to design parameters and for off design cases, example:
- LP Compressor shutdown but HP Compressor running and vice versa
- Start-up cases using gas from the gas injection well(s)
The gas system must be fitted with a gas sweetening means to ensure that the injection and lift gas will meet the H2S and CO2.
The H2S is typically set by:
- The design requirements of the fuel gas users
- To ensure an ALARP design associated with low probability high consequence events associated with gas injection riser / lift gas riser failure, or piping failure in the FPSO high pressure gas systems
- Integrity constraints associated with subsea and well design
The CO2 is typically set by:
- Integrity of the risers with respect to long term CO2 corrosion
- Requirement to minimize the amount of vented CO2 in order to minimize greenhouse gas emissions (i.e. to maximize the CO2 injected into the reservoir), within the limit of the riser integrity constraint
The waste stream from the gas sweetening unit must be managed in line with Good Oilfield Practice to ensure there is no hazard to the health of personnel and to ensure hydrocarbon losses to either vent, flare or incinerator are minimized.
Gas lift and gas injection headers must be robust for all credible low temperature events. These must include:
- The start-up case requiring the import of gas from the gas injection system following an emergency shutdown (ESD), where it will be necessary to pressure equalize across the riser emergency shutdown valves (RESDV), open the RESDV, then re-pressure the gas injection header.
- Re-pressurization of the subsea system after depressurization for maintenance or hydrate remediation.
- Manual depressurization of the subsea system from ambient seabed temperature and design pressure.
- Failure of RESDV to close on facility ESD, or leaking RESDV on ESD.
- Allowance for low temperatures resulting from the gas export hydrate management.
- Producing wells should be provided with facilities for high pressure lift gas for artificial lift. Lift gas should be delivered to the TLWP at the specified pressure and temperature via the lift gas FTL from the FPSO.
- Lift gas should be available at all production wells.
- The lift gas FTL should also provide gas supply for the gas re-injection system.
- Production wells may be set up for a turn-around operation in which production is stopped and gas is injected into the well via the production tubing. This is a secondary means of gas disposal to be used when the primary means, gas export pipeline from the FPSO, is out of service. The injected gas supply should come from the lift gas system, supplied from the FPSO via FTL.
- There should be the flexibility to inject into wells at the same time while continuing normal gas lift operations.
- A system should be provided for safe switching of wells from production to injection and vice-versa.
- Each production well should be provided with a gas lift flowline from the lift gas manifold to the surface tree. The gas lift flowline should be designed for the design pressure as specified during design consideration.
- Gas lift system design should include provisions to protect equipment and piping, including production tubing, risers and surface trees, from cold temperature due to Joules-Thompson (JT) effect downstream of the lift gas flow control valve.
- Low temperature alarm and trips should be provided after the lift gas flow control valve to safeguard the downstream system.
- Start-up should include the provision of a low temperature over-ride on the control of the lift gas flow control valve until the downstream pressure is sufficiently high enough to avoid excessively low temperatures and the use of methanol injection in the lift gas line to reduce gas volume for start-up.
- The lift gas to each producer should be individually metered and controlled by means of a flow meter and an automated flow control valve.
- The control valve should be remotely actuated from the ICSS.
- A low pressure alarm and trip should be provided between the non-return valve and the gas lift ESD valve in each flowline.
- Gas re-injection system design should protect equipment and piping, including production tubing, risers and surface trees from cold temperature due to JT effect at start-up of gas re-injection operations. The gas re-injection system should be designed to prevent hydrate formation stemming from high pressure gas re-injection into the wet production system.
- The re-injection gas to each re-injection well should be individually metered and controlled by means of a flow meter and an automated flow control valve. The control valve should be remotely actuated from the Integrated Control and Safety System (ICSS).