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Ejectors

Topic last reviewed: 10 April 2013

Sectors: Downstream, Upstream

Gas ejectors offer a reliable technology for recovering waste or surplus gas to prevent emissions whilst simultaneously conserving energy. Gas ejectors use high-pressure (HP) gas to safely and economically compress flare, vent, and surplus or low-pressure (LP) gas. When utilizing HP motive gas from existing sources, ejectors (also called eductors or jet pumps) have no running costs.

An ejector is based upon Bernoulli’s Principle which states: ‘When the speed of a fluid increases its pressure decreases and vice versa’. The ejector uses a converging nozzle to increase the fluid velocity to transform high static pressure into velocity pressure. This conversion of static pressure to velocity pressure results in a low pressure zone that provides the motive force to entrain a side fluid. The mixed fluid then flows through a diffuser section comprising a diverging nozzle that then reduces the velocity and increases the pressure, thereby re-compressing the mixed fluid. Figure 1 shows the basic components of an ejector designed for use with gas.

A gas ejector has three connection points: one for the high pressure gas; one for the low pressure gas; and one for the discharge. There is a nozzle designed to mix the two incoming streams by converting the pressure energy of the high pressure fluid into kinetic energy. The venturi shape towards the discharge end is the diffuser, which slows the mixture down and thereby increases its pressure. This enables the ejector to discharge at a pressure that is greater than that of the low suction branch. The ejector is thus capable of compressing or boosting the pressure of the entrained fluid.

Figure 1: Illustration of an ejector

This equipment has many different applications, discussed below.

  1. Ejector flare gas recovery system

System designs in which the flare gas is compressed into the fuel gas system are common. The ejector system should be designed to avoid creating a vacuum in the flare gas line to ensure safe operation.

Figure 2: Illustration of ejector flare gas recovery system

Benefits

  • Waste gas is recovered and added to production.
  • There is a potential reduction in carbon or flare tax liability, where applicable.
  1. Restart of ‘dead’ wells

This equipment can be used to restart production of existing low pressure wells which have been shut in for years due to high back-pressure. If a suitable HP well is available nearby, the pressure energy that is normally wasted across a choke could be used to drive an ejector to entrain the gas from the LP well, thereby bringing it back into production, even at times of high demand. Gas production is therefore increased.

Figure 3: Illustration of restart of ‘dead’ wells ejector application

  1. Boosting production

Gas ejector technology can also be used to boost production. Indeed, in some cases an increase in production is not possible without adding another compressor. Nevertheless, by using an ejector in the recycle line of the existing compressor, the manifold pressure of the wells is reduced and thus production is boosted. The increase in production can reach up to 15% as a function of well performance.

Figure 4: Illustration gas ejector application to boost production

Benefits

  • Cost savings relative to 2nd stage compression option.
  • Gas ejector solution is much faster to put in place than 2nd stage compression.
  • Ejector internals can be easily replaced to maximize production throughout the field life (continual reduction of well pressure).
  1. Gas recovery from storage tanks

Ejectors can be used to recover gas that is vaporized due to working losses from storage tanks (which occur when crude level changes and when crude is agitated in tanks) and standing losses (which occur with daily and seasonal changes in temperature and barometric pressure). The ejector system must be designed to avoid creating a vacuum in the storage tank vent line.

Figure 5: Illustration of gas recovery from storage tanks

Technology maturity

Commercially available?: Yes
Offshore viability: Yes
Brownfield retrofit?: Yes
Years experience in the industry: 21+

Key metrics

Range of application: Large range of applications. Can generate up to 34 Mscfd of ‘extra gas’ from shut-in wells.
Efficiency: Increase in production up to 15%
Guideline capital costs: Investment costs Involved: relatively low compared to other vacuum technologies.
Guideline operational costs: No moving parts so virtually maintenance free.
Typical scope of work description: The scope of work begins with the collection of application data. These data are critical to the proper selection and application of the technology. The basic information to be collected includes mass flow and physical properties of each component in the entrained gas stream, together with the temperature and pressure conditions for the high pressure and entrained fluid streams, as well as the discharge conditions. The scope of work must also include the design of the piping systems and valves, bypass lines, and other ancillary instrumentation.

Decision drivers

Technical: Presence of high pressure motive fluid.
Need to boost production.
Need to restart ‘dead’ wells.
Installation time (gas ejector solution is much faster to put in place than 2nd stage compression).
Feasible as an alternative to compressor installations (e.g. where there is a lack of space, no available power, or where there are cost constraints).
Operational: Low disruption in existing plant operations.
Requires a stable suction pressure to ensure reliable operation; this can be achieved in some cases through the recycle gas stream (see the section on ‘Operational issues/risks’, below).
Commercial: Relatively low costs mean project upgrades become cost-effective.
Environmental: Reduced greenhouse gas (GHG) footprint through efficiency / production rate improvements.
High GHG reduction potential when used in flare gas recovery applications.

Alternative technologies

The following technologies can provide similar benefits and may be considered as alternatives to ejector technology:

  • Compressors
  • Vapour recovery units

Operational issues/risks

Flare gas flow rate variability is common. If this variation is not controlled, the suction pressure created by the gas ejector will also vary. In order to maintain the desired pressure on the low-pressure side of the gas ejector, some standard control techniques are available including the following:

  • Recycling of gas from the discharge side of the gas ejector back into the low pressure side.
  • Incorporation of an integral HP gas regulating assembly which varies the motive fluid consumed.

Table 1: Troubleshooting tips — steam jet ejectors

Observed problem Problem source Corrective measure
Poor ejector performance, unstable operation, pressure swings  1   Lower than design motive gas pressure   1a  Raise motive gas pressure to the minimum specified by the ejector manufacturer 
1b  Bore the motive nozzle to a larger diameter to permit design gas consumption. Consult with manufacturer to determine proper nozzle diameter.
Reduced ejector capacity and an increase in suction pressure  2a Higher than design motive gas pressure 2a Reduce motive gas pressure to specified pressure
2b  Wasted gas consumption 2b  Purchase new nozzles with smaller diameters designed for the higher motive gas pressure
3   Poor ejector performance, unstable operation, pressure swings   Higher than design gas temperature  3a Raise motive gas pressure
3b  Bore the motive nozzle to a larger diameter to permit increased gas consumption-consult with manufacturer to determine proper nozzle diameter
4 Low ejector discharge temperature 4 Reduced ejector capacity 4 The motive gas may have condensate, therefore, piping must be insulated and a liquid drop-out added in the motive gas line just before the ejector 
Higher than design discharge pressure 5 Poor ejector performance, unstable operation, pressure swings 5 Look downstream for problems that could be:
a) an inter-condenser problem
b) an ejector problem
c) a restriction in the discharge piping
d) non-condensible gas load is above the design rating pressure
Higher than design suction pressure (assuming motive gas pressure is normal and discharge pressure is equal to or less than design) 6 Greater than design process load or mechanical problems with ejectors—either worn internals or possible internal gas leak around nozzle threads 6a Inspect internal dimensions and replace if necessary
6b Tighten nozzle if necessary or seal weld nozzle to motive gas supply line

Opportunities/business case

LP/LLP gas compression:

  • Increasing gas production
  • Restarting shut-in wells due to high export-pressures
  • Reducing tendency of wells to load with condensate
  • Increasing total field recovery

In the oil and gas industry typical 'motive' HP fluids are:

  • HP wells
  • Gas compression &and recycle
  • Export oil or gas
  • Fuel gas
  • Injection water
  • Gas or liquid from 1st or 2nd stage separator
  • Injection or lift gas

Advantages of ejectors compared with mechanical compressors:

  • No moving parts, hence low maintenance requirement
  • No running costs — ejectors can use HP gas energy traditionally wasted across a choke valve or HP recycle gas from an existing compressor
  • Relatively low costs mean project upgrades using ejectors become cost-effective
  • Environmentally friendly option
  • Fast-track installation makes short-term well opportunities viable
  • Minimal disruption to existing production operations
  • Low weight and compact size allow installation on most production facilities
  • Performance can be easily modified to suit depleting well conditions
  • Ejectors are suitable for both topside and subsea installation
  • Safe, reliable operation
  • Easy to control using standard techniques
  • Accidental entrainment of liquid slugs may cause momentary interruption in pumping, but no damage to equipment.
  • Low noise

Industry case studies

The case study described below provides an overview of the kind of issues that may occur during ejector implementation.

The project consisted of evaluating the benefits of installing an ejector, with Well 5 as motive fluid, and Well 1 and Well 3 as entrained fluid. The justifications for an ejector rather than a booster compressor in this particular case were:

  • The platform has no power to run an electrical compressor.
  • It is unmanned so rotating machines are avoided.
  • A gas-engine driven compressor would have been detrimental to the environment and incur the additional costs of gas consumption.
  • The ejector is a small device with no moving parts.
  • The ejector is driven by an existing force (Well 5).

Costs were driven by piping works offshore and associated production losses. One major expectation was the frequent change out of the ejector internals to cope with the decline of the production.

Important remark

The expected behaviour of each of the wells in question was difficult to forecast because:

  • Well 5 was newly developed with no historical data.
  • Well 1 stopped producing after four years due to a water cross-flow from the bottom reservoir to the top reservoir that took some time to shut off.
  • Well 3 was killed by too much formation water production after 3 years.

Figure 6: Illustration of industrial example of ejector use

Implementation of the ejector

The efficiency of an ejector increases with the differential between motive fluid and entrained fluid in terms of flow rate and pressure. For this reason the project had to be implemented quickly in anticipation of the decline of Well 5. The project was performed within eight months.

Additional dynamic information from Well 5 was gained. A redesign of the ejector was performed with the additional constraint of respecting the initial spacial footprint which was already fixed.

Results

The ejector was effective in reducing the wellhead pressures of Well 1 and Well 3 as planned but, unfortunately, the 20 bars reduction was insufficient to restart either of the two wells. The ejector was a technical success but the candidate wells did not respond as expected.

Well 1 was dewatered by means of nitrogen injection, after which it was opened with the ejector and restarted. After six months, the output was three times higher and production has been stable with the well operating on its own.

Subsequently, the ejector was connected to another well on the platform — Well 4 — where it was used successfully to stabilize and increase production. Thanks to the ejector, this previously dead well was restarted successfully.

For Well 1, the costs of the ejector installation and the nitrogen lifting operation were paid back between six months and one year after production was restarted. The internals of the ejector are changeable and the main part can be reused in a future project after the decline of Well 5.

Due to the success of this ejector, it has become established as a technology that is investigated systematically for each new project. The installation of an ejector is also a major stepping stone to other innovative projects such as wellhead compressors (subsea R&D).


References:

  1. Transvac Ejector Technology (2010). ‘Ejector solutions for the oil & gas industry’.
  2. Graham Corporation (website). ‘Troubleshooting Tips—Steam Jet Ejectors’
  3. Graham Corporation (2000). ‘Lessons from the field—ejector systems’
  4. EPA (2009). ‘Installing Vapor Recovery Units: Lessons Learned from the Natural Gas STAR Program'. Interstate Oil and Gas Compact Commission, Charleston, West Virginia, February 2009.