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   Flare Gas Recovery - By Reliance Industries Ltd. (Refinery Division)

To encourage “Energy Conservation & Environment Protection” in the Industrial sector, PCRA has been continuously upgrading their knowledge data base thru energy audits, experience in those industries and has been developing case studies for experience sharing by various Industrial groups and organizations. The case study detailed below is one of the modification carried out by Reliance refinery at Jamnagar which is being produced to disseminate the information for the benefit of petroleum refineries.


Reliance refinery at Jamnagar is worlds 3rd largest refinery and India’s biggest refinery, implemented flare gas recovery system in Nov. 2003 with inhouse design and limited help from Shell Global Solution Netherlands. This measure has reduced the quantity of hydrocarbon flaring from 53 to 10 Tons per day & controlled environmental pollution.

Hydrocarbon loss in refinery flare is a direct energy loss. The object of recovery of flare gas is to minimize hydrocarbon loss by recovering flare gas from main flare system and re-use as fuel gas in process furnaces, gas turbines, HRSGs (Heat Recovery Steam Generators) and auxiliary boilers.

A flare system is required for safety & operational reasons. As such every petroleum crude oil refinery is provided with a flaring system to continuously burn the vent gases before they are safely discharged to atmosphere. A small quantity of hydrocarbon gas is kept as purge gas in the flare system which gets burnt continuously in the flare. Also on occasions during abnormal conditions in the operation, vent-gases are sent to flare. Recovery of flare gases hence is direct fuel recovery.


At Jamnagar refinery complex, safety valve discharges and vents from all the process plants are connected to a closed flare system. There are four flare systems.

1. Main Flare System (Comprising of High & Low pressure headers)

2. Low Low Pressure Flare system.

3. Acid Gas Flare system.

4. Polypropylene plant flare system.

Since inception Ultrasonic flow meters has been provided for measuring flare gas flows of each flare system near the flare stack upstream of water seal drums. In order to avoid stagnant areas and to keep positive pressure in the flare headers, fuel gas or nitrogen purge is used.

Technique of injection of measured quantities of nitrogen in the flare header of the individual plant and analysis of flare gases (before and after nitrogen injection) at plant battery limit was used to identify the flaring quantity (by nitrogen balance) from individual plant to reduce leakages.

With all these efforts the flare loss came to about 45 TPD. The flare loss from best performing pacesetting refineries was reported to be as low as 0.03%. The mandatory purging provided in the network alone constituted about 0.05% of the refinery input.


Following methods were considered essential to reduce flare loss.

1. Review the conditions in process equipments to minimize flare control valve openings.

2. Identify leaky valves continuously and fix them

3. Consider a flare gas recovery system.

Having worked on first two methods and minimizing the flare loss, it became apparent that further reduction of flare loss is only possible by going for a suitable and well designed flare gas recovery system. The flare gas recovery system is known to be operative in some refineries internationally, while not working properly at some other places. It became clear from their experience that accurate flare load estimation was essential for successful operation of this system.

At Reliance Jamnagar, the flare gas quantity is measured near the flare stacks and flow indications are available in the system. Average and peak load data was collected and studied for 6 months operation to establish flare gas recovery design flow rate under steady state operation.

It was observed that on an average 45 TPD of hydrocarbon was getting flared regularly, out of which approximately 14 TPD was coming from Rich Anime Flash Drums in VGO hydrotreaters as per design. Another proposal existed to recover and re-use these gases. Thus the average hydrocarbon flared was expected to reduce to 31TPD. Considering continuous purging of Nitrogen at various flare headers, total quantity of approximately 52 TPD was to be compressed and re-used. After commissioning of flare gas recovery system 21 TPD purge N2 will be replace by fuel gas. Hence a system for recovering 52 TPD of flare gases including purge gas was to be installed.

Flared fuel gas contains substantial quantity of H2S. Therefore a cost effective treatment system was required to remove H2S and make fuel gas suitable for firing in heaters & recover sulphur from H2S.


The following modifications were carried out.

1. Installed a skid mounted flare gas recovery system (All wetted parts shall be of SS 316L% the material should comply with NACE MR 0175 which is suitable for H2S, chlorine and organic sulphur) involving:

  • A 20” tap off from the Main Flare header of 84” at downstream of knockout drums and upstream of liquid seal durms for the suction of Flare gas recovery compressors.
  • A set of two Liquid ring compressors to compress the flare gas from 1.1 to 8.0 Kg/cm2 Abs with mechanical seal flushing system. A by-pass line for 100% re-circulation is provided. To meet the suction pressure requirements of these Compressors, flare gas header pressure need to be increased. This necessitated re-designing the water seal drums of the flare system & revalidating the safety release system of all the operating plants connected with this system.
  • Discharge piping (6”) from compressor discharge to separator inlet.
  • Gas/liquid horizontal separator.
  • 2” piping to discharge liquid hydrocarbon from separator bottom to OWS.
  • 8” piping from separator outlet to Amine absorber inlet.
  • A shell and tube water condenser to cool the liquid ring (water).
  • Cooling water supply piping to the compressor from the exchanger and return piping from the compressor to the exchanger.

2. A Flare Gas Amine Absorber (12 valve type trays; Pressure 6.50 Kg/cm2 Abs; Temperature 40-450C; MOC-SS304)

3. 8” piping from Amine Absorber discharge to the Fuel gas header.

4. 4” piping from the Lean Amine header to the inlet of Flare Gas Amine Absorber.

5. 6” piping from the discharge of Flare Gas Amine Absorber to Rich Amine header.

Proposed Process Description

The proposed Flare Gas Recovery System (FGRS) is a skid-mounted package consisting mainly of two compressors which take suction from the flare gas header upstream of the Liquid Seal Drum, compresses the gas and cools it for re-use in the Refinery Fuel Gas System.


Normally the flare gases bubble through water seal in the seal drum upstream of the flare stack. The liquid level in the seal drum imposes a positive backpressure in the flare header and thus ensures that air is not drawn into the flare system. For providing a better suction pressure while avoiding air ingress to suction of flare gas recovery compressor, modifications are required to be carried out to increase the water level in the water seal drum.

FGRS is located downstream of knockout drums as all flare gases from various units in the refinery is available at this single point. It is located just upstream of the seal drums as pressure control at the suction to compressor will be maintained precisely, by keeping increased height of water column in the drum.

The flare gas enters the compressors at 1.1 Kg/cm2 Abs and 380C. A continuous re-circulating flow of process water enters the compressors for compression, sealing and cooling of gas.

After leaving the compressors the gas, water and hydrocarbon mixture enters the Gas/Liquid separator where the compressed gas is separated from the water and condensed hydrocarbons by gravity due to lower gas speed. The separated flare gas passes through demister before leaving the G/L separator in order to have a minimum water and condensed hydrocarbons content in the outlet gas stream and leaves from the top at 8.0 Kg/cm2 Abs and about 500C. The process water leaves the G/L separator from the bottom where it is pushed back to the compressors due to the pressure differential between G/L separator and compressor inlet (liquid ring).

The normal operating liquid ring flow rate is about 32 m3/hr. at 380C. A common shell and tube cooler on the liquid ring line assures the continuous cooling of the ring and therefore isothermal gas compression. The cooler is designed for the duty of two compressors.

The flare gas is dry but during compression process it becomes saturated with water. This causes a continuous water decrease in the system. Due to this fact and to clean up the liquid ring process water from hydrocarbons, a continuous process water make up line in the compressor suction line is provided.

The condensed hydrocarbons overflow into OWS from where they are discharged by means of level control valve. The process water overflows through a weir into a collecting compartment. The level into the compartments is guaranteed by the control valve that is controlled by the level transmitter. The excess water is sent to OWS.

The unit has a by-pass between the inlet and outlet of the unit to control the inlet line pressure. If the inlet pressure decreases below a certain value the valve starts opening till full recycle is established (no gas available).

The gas stream from the G/L separator is routed to the Flare gas Amine Absorber where the gas is amine treated to remove H2S present in the gas. The treated gas from the Amine Absorber goes to the Fuel Gas header.

If the volume of gas relieved into the flare system exceeds the capacity of FGRS, the excess gas volume will flow to flare stack. If the volume of gas relieved into the flare system is less than the full capacity of the recovery unit, a spillback valve will divert the discharged gas back to the suction header, to maintain the capacity of FGRS.

Choice of Compressor

Liquid-ring compressor is preferred and most suitable over the other types (i.e reciprocating, screw, centrifugal etc.) available in the market for this service, since it ensures near isothermal compression and an intrinsically explosion-proof operation. It can handle a wide variation in flow rate, dirty gas, liquid slugs and solids. Liquid-ring compressors use a liquid (water) to form a seal in the shape of a ring between the outer ends of the impeller and compressor housing. The centrifugal force of the rotating impeller forces liquid to the outside wall forming a seal.

As the operating fluid absorbs most of the heat of compression, there is minimal rise in recovered gas temperature during compression. The compressor doesn’t require any after cooler. After separation of the compressor operating liquid from the gases, the operating liquid will get discharged from the separator and is cooled through a heat exchanger. Once the operating liquid is cooled, it returns to the compressor where it is re-used to create the compressor seal. No separate booster pump is required to move the operating fluid from the separator to the compressor. Due to presence of sour gases the quality of operating liquid needs to be strictly maintained to prevent acid build up and contamination of the operating fluid. Liquid bleed and fresh water make-up capabilities have been provided which will operate as necessary.

Flare Header Pressure Control

For safe operation of FGRS it is mandatory to eliminate the possibility of air being sucked into the flare gas system, since the composition is normally of hydrocarbons and hydrogen sulphide but also of hydrogen, what when mixed with air can be highly explosive. To avoid ingress of air into flare header, it is required to maintain always a positive suction pressure at around 150-200 mm water gauge (water seal level in drum needed adjustment) . In case of reduction of suction pressure, compressor spillback valve will open to recycle compressed gas back to compressor suction.

Seal Drum Modifications

Modifications to the existing seal drums were necessary to have a bandwidth for pressure control of the flare gas recovery system. The seal height has to be increased from existing 127 mm to 1000 mm. The increase in submerged portion of dip-legs was achieved by increasing the liquid level in the vessel by 873 mm.


The above modification called for an investment of Rs. 10.08 Cr and the savings achieved are Rs. 14.0 Cr./annum with a payback period of 9 months.

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