Inlet Separation and Filtering

Introduction

Feed gas is available at the battery limit of FNNPF Plant through the 24” Encana connector pipeline, joining the feed gas pipeline with the Receiving Station located at the edge of the plant. The normal arrival pressure is 1100 psig, whereas the maximum arrival pressure can go up to 1170 psig. The receiving station is provided with an ESD skid, custody transfer meter, CO2 & H2S analyzers and the plant flow meter. The receiving station is designed for 1300 psig pressure.

The inlet gas then flows to the following stages:

Inlet Gas Measurement: gas enters the process plant to be measured

Raw Gas Separation: the gas has any entrained liquids or containments removed

Raw Gas Filtration: the gas is has any remaining liquids or containments removed

Inlet Gas Flow

Referring to figure 2 the FNNPF’s raw gas inlet flowline in the inlet/outlet building consists of the following:

• 2 manual raw gas inlet block valve and 2 inch vent to depressure to safe location

• Process raw gas inlet ESD valve (XV-8003)

• Meter run

• Inlet gas analyzer

Inlet Gas Block Valves

The 16” raw gas inlet flowline is equipped with a manual inlet block valve upstream and downstream of the Inlet ESD valve. These block valves are normally open. In addition a corrosion coupon is located at the start of the inlet piping to monitor corrosion rates.

Purge Valving

Directly upstream of the ESD (XV- 8003) valve is a 2” high-pressure purge gas tie-in for use during turnaround purging/sweeping, and train repressuring. The purge gas flowline is as follows:

• the purge gas flowline is equipped with local manual valving that is normally closed

• the purge gas flow is normally blinded (or car sealed closed) to prevent the higher pressure raw gas from potentially entering the purge gas piping and souring the FNNPF sales gas flow. The purge gas originates as high-pressure buyback fuel gas from the outlet sales gas flow.

Inlet ESD Valve

The raw gas inlet ESD valve (is located directly downstream of the manual raw gas inlet block valve). The ESD valve is triggered to close automatically in response to alarm/emergency conditions. The valve is only used to isolate the inlet gas from the process – it never acts to control inlet pressure or flow as it is either fully open or shut. The operation of the ESD valve is triggered as follows:

• Alarm/emergency conditions triggered by the safety system or DCS which initiates the automatic closure of the ESD valve to process from the raw gas inlet.

• The FNNPF Control Room Operator can:

- remotely trigger the closure of the ESD valve using onscreen controls at the DCS workstations

- remotely reset the ESD valve using the onscreen selection

- remotely reopen the ESD valve

The ESD valve has local open/closed position indication. As well, the valve position is relayed to the Control Room. The valve can also be operated in local operation, in the event that the valve cannot close from the Control room. At the request of the Control room operator, the area operator will switch the valve over to local operation and use instrument air to close the valve.

Inlet Gas Run

The gas after flowing through the ESD valve then enters the meter run where the flow, temperature and pressure is recorded in a flow computer. This computer will automatically and accurately adjusted the process to be the most efficient for the gas quantities entering the plant.

Inlet Raw Gas H2S/CO2 Analyser

The inlet gas analyzers function as follows:

• The analyzers measure the concentration of H2S and CO2 in the incoming raw gas and then discharges the gas sample via an outlet valve to FNNPF’s HP flare system.
• The analyzer’s measurement data are relayed to the FNNPF’s Control Room where the H2S and CO2 concentrations appear onscreen at the DCS workstations.

Operations Monitoring

The FNNPF Control Room Operator monitors the onscreen H2S and CO2 readings from the analyzer. Vigilantly monitoring the readings provides the first indication of swings or spikes in the acid gas content that may impact the FNNPF’s sweetening operations.

Important

Any change to the inlet gas analyzer (e.g., blocking in, flaring, repair, or calibration) must be relayed to the Control Room Operator.

Inlet Gas Flow to Inlet Seperation

After the raw gas leaves the inlet metering and flow piping it enters the Inlet Separator. Liquids (such as corrosion inhibitor, down hole chemicals, lube oils, etc) must be removed as they could contaminate the amine and produce unwanted side effects in the sweetening unit (tower foaming, accelerated production of amine degradation products, increased corrosion, etc.). These liquids are most likely to be present when pipeline pigging occurs but trace liquids are possible at any time. To limit the problems caused by these liquids an inlet separator and Inlet Gas Filter (FI-1105) are part of the design prior to the gas reaching the Amine Contactors (PV-1101 A/B).

Operation

The Inlet Gas Separator (PV-1109) to knock out any liquid or solids entrained in the gas. An Inlet pressure controller (PV-1000) is provided to supply a constant pressure so that the process plant pressures do not fluctuate with pipeline pressures. The outlet gas from the separator goes to the Inlet Gas Filter (FI-1105). The interconnecting pipeline and the high pressure portion of the gas plant are all designed for 1,300 psig.

The separator is of a vertical design and consists of two separation stages (figure 3).

• First Stage" uses volume and upwards gas flow diversion to remove entrained liquids from the gas stream. Any liquids captured are drawn off through a level control valve to the HP Flare Knockout Drum where it is finally collected in the hydrocarbon drain tank. Liquids are drained off through a vortex breaker which prevents swirling of the liquid as it drains out and eliminating the possibility of gas being sucked into the drain line. The gas then flows upwards and down into the second stage.

• Second Stage:The gas then flows into the second stage into a cyclotube which enhances the removal of containments by creating a centrifugal force on the gas. This force spins out the remaining liquids into the second stage collection area where, through a level control valve, liquids are drawn off to the hydrocarbon drain tank via the HP Flare Knock-out Drum.

On the outlet of the Inlet Separator an ESD/control valve is located to safely vent high pressure gas in the event of a total plant safety system ESD or DCS controlled operation (refer to induction module for full description of valve types used in emergency conditions). Through blind manipulation, gas is then sent to the Inlet Gas Filter (normal operation) or directly to the contactors.

Process Controls and Instrumentation

The Inlet Separator consists of 2 scrubbing sections:

1. The bottom section is used to catch any inlet slugs of liquid and do the primary separation (i.e. scrub out any large liquid droplets). The separated liquids are level dumped by( LV-1004A) or (1004B) to the HP flare header. These valves are operated by (LIT- 1004). One of the valves are always manually blocked in, and is to be used for standby operation.
2. The 2nd stage of scrubbing is intended to catch the smaller droplets that may carry through the bottom section. The gas flows down a number of large cyclones which cause the smaller droplets to separate out and collect in the top section of the vessel; these liquids are then also level dumped by (LV-1007) to the HP flare header. This valve is opened and closed by (LIT-1007).

Due to the potentially low normal liquid rates the liquid dump valves (LV-1004 A/B and LV-1007) are on/off control. This will limit potential seat damage which could occur if the valve were operated continually at a nearly closed position. Flow restrictors (chokes) have been included downstream of the control valves to limit potential gas blow.

(PV-1009) is also equipped with a pressure relief valve (PRV-1001) on the inlet piping downstream of the inlet pressure control valve. This PRV is a safety device to release pressure from the vessel in the event of a building fire it is set at 1300 psig, it will release gas in a high pressure situation to the high pressure flare system. In the event of a fire occurring, it would prevent gas that could potentially be trapped in the vessel form heating and expanding and possible rupturing the vessel.

Each compartment is also equipped with high and low level alarms that alarm into the DCS, if an abnormal level is reached.

Each level of the inlet separator is also equipped with a magnetic gauge glass, for local level indication, this level is also transmitted into the control room in a 0% to 100% value. The Top Gauge Glass is (LG-1007), the Lower Level Gauge Glass is (LG-1004).

(PV-1009) is also equipped with a Differential Pressure Transmitter (PDI-1009). This will alarm in at 8psi differential between the upper and lower zone of the separator. A high differential would indicate fouling or hydrating off of the separator.

Other instrumentation on (PV-1109) includes:

• (TI-1003) for local temperature indication
• (PI-1003) for local pressure indication

Additional Specialty Lines and Valves

The Inlet separator is equipped with the following:

• manual drain valves on the separator and its associated level columns tie into the HP flare header
• two top vent valves to atmosphere
• a 65# steam purge line (normally blinded and blocked in) is used only for-turnaround and shutdown steam purging

Operations Monitoring

The Area Operator’s monitors the inlet separator as follows:

• confirms that the separator level control valve is closed in and confirms its manual bypass valve and downstream block valve are fully closed (when the inlet piping is not being pigged)
• monitors the level in the gauge glass to ensure that little (if any) liquid has accumulated
• manually blows down each separator every night to drain accumulated liquid to the LP flare knockout drum
• blows down the level glass (when necessary) to ensure the stagnant liquid level won’t be misread

If an inlet separator’s level rises above normal, the Area Operator:

• ensures the HP flare knockout drum has enough storage space to receive the liquid
• discusses any abnormal liquid accumulation with the Control Room Operator
• uses the level control valve to expel the accumulated liquid.

Note:

The Area Operator may use the control valve’s manual bypass valve to expel the liquids if there are problems with the level control valve or if the operator feels the need to prove the bypass line clear. The Area Operator may also do the same for the belly drain.

Area Operator's Role During Pigging

During the regular pigging of the Encana 24" inlet line into FNNPF, a pig is used to clean the pipeline. The pig pushes any liquid that has accumulated in the line into the plant. If liquid is present, the slug of liquid will enter the primary inlet separator and cause the level in the separator to rise. (An increase in level will also occur in the secondary inlet separator.) Before the pig is scheduled to arrive, the Area Operator prepares as follows:

• manually blows down the inlet separator to prove that the liquid piping is clear

The Area Operator stands by at the inlet separators to manually drain any accumulating liquid. The Area Operator notifies the Control Room Operator if liquids are present.