API RP 19G13 --- Section 5.2 --- Normal Pressure Sub-Sea Gas—LiftPage 1

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5.1

5.2Recommended Practices for Normal Pressure Sub-Sea Gas-Lift

This section contains recommended practices that are specific and/or unique for normal pressure sub-sea gas-lift. The general recommended practices in Section 5.1 are not repeated here.

  • Recommended Practices for Normal Pressure
  • Author: Mike Johnson

These recommended practices are unique to “normal pressure” sub-sea gas-lilt operations. Normal pressure is defined as gas-lift injection pressure less than 2000 psig.

Please make certain that the following unique items are addressed in this Section 5.2:

  • Specify the minimum design validation and functional evaluation requirements for gas-lift equipment.
  • System elements and design considerations.
  • Pre-installation requirements.
  • Start-up considerations.
  • Operational and maintenance considerations.
  • Intervention considerations
  • Root cause of failure analysis.
  • Data collection requirements.
  • Reference standards.

Note. Making modifications to sub-sea gas lift installations is usually very expensive. This includes, for example, the replacement of subsea flow meters or chokes, or changing-out gas lift valves. It is therefore paramount to select the best equipment available for such applications, and to design for robustness. In many cases it is possible to build in redundancy at little extra cost. This provides a fall-back option in case of failing hardware where replacement is not economic.

Note. Highlightitems inbold redthat need to be defined in Terms and Definitions.

Note: The following sub-sections are taken from API RP 19G13, Section 5.1, Common System Elements. Under each sub-section, the text is copied from Section 5.1 and is shown in red. This is to make it easy to see the text from Section 5.1 without needing to open an extra document. The goal here, under each sub-section, is to add information that is unique to sub-sea gas-lift, if any additional items are needed. It information needs to be added to this Section 5.2that doesn’t fit under one of the existing sub-section headings, additional sub-sections may be added.

When this Section 5.2 has been drafted, the “red” text below will be removed so all this is left will be each section heading and new items that have been added. If it is necessary to make any changes to the “red” text, send a note to Wayne Mabry or Cleon Dunham. Do not change it here. The sub-section numbers shown below are identical to the same sub-section numbers inSection 5.1. When this section is completed, the sub-section numbers will be changed to be part of Section 5.2.

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5.1

5.1.1Common System Elements

5.1.1.1Recommended Practices for Material Selection (e.g. high pressure, high temperature, H2S, CO2)

  1. Design all pressure containing equipment for the life of the well, specificallly addressing applicable codes, pressuire ratings, tri-axial stress conditons for the worst cases for maximum and minimum pressures and temperatures that may be encountered.
  1. Predict worst case conditions for the occurrence of H2S, CO2, and water vapor in the lift gas, gas hydrates, asphaltines, and other fluids introduced during the life of the well. Obtain reservoir fluid samples for PVT analysis and detailed composition. Select materials that are designed for the environments that will be experienced, especially considering the worst case of expected pressures and temperatures.

Use the recommended practices in Section 5.1 that are common to all challenging gas-lift applications. The following items, if any, are unique to normal pressure sub-sea gas-lift wells.

5.1.1.2.Recommended Practices for Surface Equipment

  1. Safety is of paramount importance in extreme gas-lift environments. Design all surface equipment for fail-safe operation. Recommended practices for verification of the designs are presented in the section on Installation.

Use the recommended practices in Section 5.1 that are common to all challenging gas-lift applications. The following items, if any, are unique to normal pressure sub-sea gas-lift wells.

5.1.1.2.1.Practices for Dehydration

  1. Dehydrate all lift gas to at least three pounds of water vapor per million cubic feet of gas, or lower if necessary to prevent hydrate formation. This is essential to prevent any risk of corrosion or problems that may arise due to liquid accumulation or hydrate formation in the gas-lift system.
  1. Minimize disruption in the dehydration process to reduce the off-specification gas that enters the gas-lift distribution system.
  1. Gas pressure systems designed for single point injection may require discharge pressures ranging from 2000 psig to 6000 psig or higher. Dehydration should be done at an inter-stage pressure between 800 psig to 1200 psig to eliminate excess glycol carryover with high density gas.

Use the recommended practices in Section 5.1 that are common to all challenging gas-lift applications. The following items, if any, are unique to normal pressure sub-sea gas-lift wells.

5.1.1.2.2.Practices for Compression

  1. Select the compressor discharge pressure with the first priority being safety. Design a discharge pressure that is as high as is safe and feasible to minimize the number or eliminate unloading gas-lift valves.
  1. Use centrifugal compressors for greater capacity, lower weight and vibration, smaller foot print, and higher reliability; use reciprocating compressors for lower capacity, better rate flexibility, and insensitivity to gas molecular weight changes.
  1. Provide as much redundancy for the lift gas compression system, including the compressors and prime movers, as is economically feasible. A detailed plan for start-up and/or re-start is required that addresses HSE and systems interactions.
  1. Provide instrumentation and logic to continuously monitor the compression system and evaluate its performance.
  1. Equip the compression facility with vibration monitoring to detect and address any installation or alignment problems.

Use the recommended practices in Section 5.1 that are common to all challenging gas-lift applications. The following items, if any, are unique to normal pressure sub-sea gas-lift wells.

5.1.1.2.3.Practices for Lift Gas Distribution

  1. Provide redundant lift gas distribution lines to the extent that is economically feasible.
  1. Right-size the distribution lines to minimize pressure drops between the compressor discharge and the gas-lift injection manifold or wellhead.
  1. If there are low spots in the distribution system, provision of adequate dehydration is even more important to prevent of liquid accumulation and slugging.
  1. Provide a mechanism to purge the distribution system lines of liquids, and use pig launchers/receivers on the large constant diameter pipelines from the compressor station. When pigging operations are being used, a detailed plan is required that addresses HSE and system interactions.
  1. Provide instrumentation and logic to continuously monitor the distribution system and evaluate its performance.
  1. Provide automated control valves, with manual back-up, to control the gas flow into the distribution system and the flow from the system to the gas-lift wells.

Use the recommended practices in Section 5.1 that are common to all challenging gas-lift applications. The following items, if any, are unique to normal pressure sub-sea gas-lift wells.

5.1.1.2.4.Practices for Lift Gas Injection Manifold

  1. Measure the lift gas pressure, temperature, and flow rate upstream of the manifold. This can be used to double check the total rate of lift gas in the system and the rate being injected into each well.
  1. Measure the lift gas flow rate to each well immediately downstream of the manifold or at the wellhead. The pressure and temperature upstream of the manifold can be used to compensate gas flow rate measurements to each well served by the manifold.
  1. Provide automated flow control valves to control the gas flow from the manifold to the individual wells.
  1. Provide automated shut-in valves, with manual back-up, if feasible, that can be used to provide a positive shut-off of gas flow to any particular well.

Use the recommended practices in Section 5.1 that are common to all challenging gas-lift applications. The following items, if any, are unique to normal pressure sub-sea gas-lift wells.

5.1.1.2.5.Practices for Lift Gas Measurement and Control

  1. Implement the recommendations for measurement and control equipment that are provided in Section 5.1.d.
  1. Use high quality measurement and control devices. Failures and poor performance are not acceptable.
  1. Install measurement and control devices so they can be maintained and calibrated or verified without interrupting gas flow in the system.
  1. Install measurement and control devices to avoid low spots where liquids can accumulate and any sharp bends where erosion may occur.
  1. Equip each automated lift gas flow control valve with a position feedback sensor and implement an algorithm to calculate the lift gas flow rate based on valve Cv, valve position and differential pressure. This provides a redundant option if the lift gas flow meter fails.

Use the recommended practices in Section 5.1 that are common to all challenging gas-lift applications. The following items, if any, are unique to normal pressure sub-sea gas-lift wells.

5.1.1.2.6.Practices for the Wellhead

  1. Install pressure measurement instruments to measure gas injection pressure directly on the casing head, downstream of any pressure restrictions or control devices.
  1. Install pressure measurement instruments to measure production pressure directly on the tubing head, upstream of any pressure restrictions or control devices.
  1. Minimize use of 90o elbows and reduced inside diameter (ID) valves that create potential flow restriction or erosion.
  1. Install automatic control valves so the well can be positively shut-in remotely. Provide manual back-up valves, where feasible, for shut-in if the automation system fails.
  1. Install automatic adjustable control valves or chokes so the well’s lift gas injection rate can be adjusted if it is not controlled at the injection manifold.
  1. Install automatic adjustable production control valves or chokes so the well’s production rate can be adjusted if necessary to minimize instabilities.
  1. If instability can be controlled or eliminated by injection control of lift gas, remove chokes and choke bodies from existing wellheads to minimize flow restriction.

Use the recommended practices in Section 5.1 that are common to all challenging gas-lift applications. The following items, if any, are unique to normal pressure sub-sea gas-lift wells.

5.1.1.2.7.Practices for Surface and Sub-Surface Annular Safety Systems

  1. Perform a risk-based evaluation of containing high-pressure lift gas and consider the use of surface and sub-surface annular safety systems.
  1. If an annular safety system is to be used, select materials for the valve and control line that are compatible with the downhole environment.
  1. If a control line is used, the protection system must prevent damage to the line during the running operation.
  1. Comply with regulatory requirements for testing procedures and frequency.
  1. Comply with manufacturer’s start-up and operating procedures to avoid damaging the system. A detailed plan is required that addresses HSE and system interactions.

Use the recommended practices in Section 5.1 that are common to all challenging gas-lift applications. The following items, if any, are unique to normal pressure sub-sea gas-lift wells.

5.1.1.2.8.Practices for the Flowlines

  1. Design flow lines to minimize pressure drops between the wellhead and the production manifold, but don’t oversize the lines to avoid severe slugging that may arise in later life when the production rates of the wells may decline.
  1. Provide a mechanism to clean the flow lines if paraffin or solids accumulate in them. Provide access to circulate fluids from a host platform or FPSO for cleaning or displacement required for shutdown periods.
  1. Provide automated control valves, with manual back-up, if feasible, to permit flowlines to be serviced and pressure tested.
  1. Provide instrumentation and logic to continuously monitor the flow lines and evaluate their performance. As a minimum, measure the pressure entering the flowline at the wellhead and the pressure entering the production manifold.

Use the recommended practices in Section 5.1 that are common to all challenging gas-lift applications. The following items, if any, are unique to normal pressure sub-sea gas-lift wells.

5.1.1.2.9.Practices for the Production Manifold

  1. Design the production manifold so each well can be automatically switched into each production pressure system, if there is more than one system.
  1. Design the manifold so each well can be automatically switched into the well test system.
  1. Provide automated control valves, with manual back-up, if feasible, to permit the wells to be automatically or manually switched.
  1. Design the manifold so any valve can be isolated for maintenance without interrupting flow through the manifold.

Use the recommended practices in Section 5.1 that are common to all challenging gas-lift applications. The following items, if any, are unique to normal pressure sub-sea gas-lift wells.

5.1.1.2.10.Practices for Well Testing

  1. Measure oil, water, and gas rates separately by using three-phase well test separators if the separators are available for the wells.
  1. Measure oil and water rates with appropriate metering devices for the fluid characteristics and location. Choices include turbine, coriolis density, and multiphase meters.
  1. Measure gas production rate with appropriate metering devices for surging gas flow. Choices include orifice, sonic, coriolis density, and multiphase meters.
  1. Provide a process to calibrate the well test meters without disrupting flow in the production station or platform.
  1. Measure and control the pressure in the test separator so it is equal to the pressure in the bulk separator. If the test separator must be a higher pressure, apply the correct shrinkage factors to both test and bulk separator liquid rates.
  1. Provide a process to clean the separator without disrupting flow in the production station or platform.
  1. Automate the well test process so each well test time is suitable for the objective, for example a quick surveillance test, a test to identify problems, or a regulatory test.

Use the recommended practices in Section 5.1 that are common to all challenging gas-lift applications. The following items, if any, are unique to normal pressure sub-sea gas-lift wells.

5.1.1.2.11.Practices for Separation and Treating – Separator, FWKO, Heaters, Treaters, Tanks, Pumps, etc.

  1. If pertinent, provide multiple production pressure systems. The gas-lift wells should normally be produced into the lowest pressure system. Flowing wells may be produced into higher pressure systems.
  1. Measure oil, water, and gas rates separately by using three-phase production separators.
  1. Use turbine or equivalent meters, rather than “dump” meters, to measure oil and water rates.
  1. Use turbine meters, orifice meters, or equivalent to measure gas production rates.
  1. Provide a process to calibrate the production meters without disrupting flow in the production station or platform.
  1. Measure the pressure of the production separator and use a back pressure regulator to keep the pressure of the separator constant.
  1. Provide a process to clean the separator without disrupting flow in the production station or platform.
  1. Design the production equipment - free-water knockouts, heaters, treaters, tanks, pumps, etc. to maintain minimum back pressure on the production system.

Use the recommended practices in Section 5.1 that are common to all challenging gas-lift applications. The following items, if any, are unique to normal pressure sub-sea gas-lift wells.

5.1.1.3.Recommended Practices for Sub-Surface Equipment

  1. Design all sub-surface equipment for the highest degree of safety and reliability. In most cases, the equipment must function for the life of the well as access to the wellbore for maintenance and/or replacement of downhole equipment will, at best, be very difficult and expensive, and it may be completely unfeasible.

Use the recommended practices in Section 5.1 that are common to all challenging gas-lift applications. The following items, if any, are unique to normal pressure sub-sea gas-lift wells.

5.1.1.3.1.Practices for Gas-Lift Mandrels

  1. Before selecting gas-lift mandrels, determine if single-point injection will be sufficient, or if unloading valves that will need multiple mandrels will be required.
  1. Use side-pocket mandrels with a pressure rating compatible with the worst case pressures and temperatures at well depths that are designed to accept gas-lift valves installed by wireline or coiled tubing.
  1. Order gas-lift mandrels using the API 19G1, ISO International Standard 17078-1. Use the highest Design Validation Requirement V1, the highest Product Functional Requirement F1, the highest Quality Control Requirement Q1, and the Environmental Service Requirement E1 – E4 depending on the level of service required.
  1. Use mandrels with the largest pocket bore size that are compatible with the tubing selected for the well.
  1. If more gas must be injected than can flow through the gas-lift valve that fits in the selected pocket bore, increase the pocket bore diameter to accommodate a larger valve, or use two or more mandrels located one above the other, one tubing joint apart.

Use the recommended practices in Section 5.1 that are common to all challenging gas-lift applications. The following items, if any, are unique to normal pressure sub-sea gas-lift wells.

5.1.1.3.2.Practices for Gas-Lift Valves

  1. Before selecting gas-lift valves, determine if single-point injection will be sufficient, or if unloading gas-lift valves that will be required.
  1. Use the largest diameter gas-lift valves that are compatible with the selected mandrels that can be installed with wireline, tractors, or coiled tubing. Avoid use of 1.0-inch or smaller valves if possible.
  1. Order all gas-lift valves using API 19G2, ISO International Standard 17078-2. Use the highest Design Validation Requirements V1, the highest Product Functional Requirements F1, the highest Quality Control Requirements Q1, the Environmental Service Requirements E1 – E4 depending on the level of service required.
  1. If the well’s conditions are more severe than the API/ISO design/validation conditions that were used in the original testing, then additional testing may be required. These might include:
  • Bellow life-cycle testing at pressures consistent with actual operating pressures.
  • Testing at temperatures consistent with actual operating temperatures.
  • Additional testing at higher wellbore deviations than 45o.
  1. API 19G2 specifies fresh water for erosion testing. If a more erosive fluid is to be flowed through the valve at rates higher than those qualified, additional testing may be required.
  1. If more gas must be injected than can flow through the selected gas-lift valve, increase its diameter or use two or more valves located one above the other, one tubing joint apart.
  1. If single-point injection will be used, use an orifice valve for the point of injection.
  1. Use a venturi-type orifice instead of a square-edge orifice to ensure stability if there is little pressure margin between available supply pressure and expected casing head pressure
  1. If single-point injection will be used and the well will not require gas lift initially, shear-type valves are recommended. These valves prevent annulus fluids from entering the tubing when the pressure in the tubing drops below the pressure in the annulus at the injection point. This may lead to a large vacuum above the liquid level in the annulus.
  1. If unloading gas-lift valves will be required, use injection pressure operated (IPO) valves for unloading and an orifice valve for the point of injection.
  1. Use back-check valves in all gas-lift valves and orifices that are designed to be leak tight and are tested with a maximum leak rate of 1.0 Ft3 of gas per day.
  1. In applications where barrier-qualified gas-lift valves are required, additional testing will be required. See testing requirements in the Norwegian barrier standard WR0534.
  1. Use tungsten carbide balls and seats, or other materials that have equal or grater erosion resistance, on gas-lift valves to minimize the possibility of erosion.
  1. Test each gas-lift valve before installation to verify its opening pressure, closing pressure, flow coefficient, load rate, maximum stem travel, and back check integrity.

Use the recommended practices in Section 5.1 that are common to all challenging gas-lift applications. The following items, if any, are unique to normal pressure sub-sea gas-lift wells.