Process and Utility Description CDS

TABLE OF CONTENTS ABBREVIATIONS ...................................................................................................................................................... 3 1.0

PROJECT INTRODUCTION ............................................................................................................................ 4

2.0

PROJECT SCOPE .......................................................................................................................................... 5

3.0

PURPOSE OF DOCUMENT ........................................................................................................................... 6

4.0

CENTRAL DEGASSING STATION ................................................................................................................... 6

4.1 4.2 a) b) c) 4.3 4.4 4.5 4.6 4.6.1 4.6.2 4.7 4.8 4.9 4.10 4.11 4.11.1 4.11.2 4.11.3 4.12 4.12.1 4.12.2 4.12.3 4.13 4.14 4.15 4.16 4.17 4.17.1 4.17.2

WELL HEAD ............................................................................................................................................................. 6 INLET FACILITIES ........................................................................................................................................................ 6 Multi‐Selector Manifolds ...................................................................................................................................... 6 Production Headers, Test Headers and MPFMs ................................................................................................... 7 Pig Receivers and Production Manifolds .............................................................................................................. 7 PRODUCTION SEPARATORS .......................................................................................................................................... 7 CRUDE OIL EXPORT SYSTEM ........................................................................................................................................ 8 PRODUCED WATER HANDLING .................................................................................................................................... 9 GAS COMPRESSION AND DISTRIBUTION ....................................................................................................................... 10 Gas Compressor: ................................................................................................................................................. 10 Injection Gas distribution ................................................................................................................................... 12 GAS DEHYDRATION .................................................................................................................................................. 12 CHEMICAL INJECTION SYSTEMS .................................................................................................................................. 13 VAPOR RECOVERY ................................................................................................................................................... 13 FUEL GAS .............................................................................................................................................................. 14 FLARE SYSTEMS ....................................................................................................................................................... 14 HP, HP Cold and HP Spare Systems .................................................................................................................... 14 Tank Flare System ............................................................................................................................................... 15 Flare Drain System .............................................................................................................................................. 16 PROCESS AND CLOSED DRAINS ................................................................................................................................... 16 Closed Drain System ........................................................................................................................................... 16 Process Drain System.......................................................................................................................................... 17 Tundish System ................................................................................................................................................... 17 COMPRESSED AIR SYSTEM ........................................................................................................................................ 17 NITROGEN GENERATION SYSTEM ................................................................................................................................ 18 DIESEL FUEL ........................................................................................................................................................... 18 EMERGENCY DIESEL GENERATOR ................................................................................................................................ 18 POTABLE WATER SYSTEM ......................................................................................................................................... 18 Potable Water Generation System ..................................................................................................................... 18 Potable Water Storage and Distribution ............................................................................................................ 19

5.0

REFERENCES ............................................................................................................................................. 20

6.0

ANNEXURES ............................................................................................................................................. 20

DOCUMENT TITLE: PROCESS AND UTILITY DESCRIPTION CENTRAL DEGASSING STATION CONTRACTOR DOC. No. A049-001-02-41-PD-1001

PROJECT No. :P 14364 ADCO DOC. NO.: 58.01.91.1601 REV 1

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ABBREVIATIONS ADCO

Abu Dhabi Company for Onshore Oil Operations

BOPD

Barrels of Oil per Day

BPD

Barrels Per Day

BWPD

Barrels of Water per Day

CDS

Central Degassing Station

FEED

Front End Engineering Design

GASCO

Abu Dhabi Gas Industries

HP

High Pressure

IA

Instrument Air

KO

Knock Out

LAH

Level Alarm High

LAL

Level Alarm Low

LP

Low Pressure

M

Thousands

MOL

Main Oil Line

MPFM

Multiphase Flow Meter

MSM

Multiselector Manifold

RDS

Remote Degassing Station

SCFD

Standard Cubic Feet per Day

Th-A/B

Thamama-A and Thamama-B (producing zones)

Th-F

Thamama-F (producing zone)

VRC

Vapor Recovery Compressor



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1.0

PROJECT INTRODUCTION ADCO has been chartered by their shareholders to expand sustainable crude oil production from its current level of 1.4 million barrels oil per day (MMBOPD) to 1.8 MMBOPD. Accordingly, ADCO has undertaken projects for development of its marginal fields to help achieve this target, which involves increasing production at existing Bab & North-East Bab oil fields and beginning productions from two new oil fields, namely, Bida Al Qemzan & Qusahwira. Qusahwira is a new undeveloped field located about 80 Km Southeast of existing Asab oil field and approximately 200 km south-southeast of Abu Dhabi city. The location of the Qusahwira field is depicted in Figure 1-1 below: Figure 1-1

The development drilling commenced at the end of year 2006 & full field development shall be completed in two phases. The development under Phase-1 is limited to the southern block of the field, which involves developing Thamama Zones A/B and F. The first phase of Qusahwira project will contribute 30 MBOPD to 1.8 MMBOPD scheme from year 2013 for a period of about five years. After completion of second phase, its total production shall increase to 42.47 MBOPD. Additionally, 20 MBOPD from Mender and South East fields shall be implemented in future.



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2.0

PROJECT SCOPE The Phase-1 of Qusahwira Full Field Development Project shall have facilities at three locations and an interface with the existing Asab oil field. Broadly, the following facilities are part of Phase-1 project: -

Constructing a new Central Degassing Station (CDS) at Qusahwira. It shall include facilities as below: o

Inlet manifolds for receiving production transfer line from a new Remote Degassing Station (RDS-1) & two direct production flow lines

o

Multi phase flow meters (MPFMs)

o

Two trains of three phase production separators

o

Two trains of four stage gas compression

o

Gas injection directly to four gas injection wells

o

Two glycol contactors & one common glycol regeneration

o

Vapor recovery compressor package

o

Produced water treatment & disposal to five disposal wells

o

Main oil Line (MOL) booster pumps and MOL pumps for exporting crude oil to Asab CDS

o

Various supporting utilities & chemical injections systems.

-

Constructing a new Remote Degassing Station (RDS-1) at approximately 9.2 km southwest of the new Qusahwira CDS. The RDS -1 shall gather & test 22 production flow lines and deliver the raw crude to the Qusahwira CDS. This shall also serve as distribution points for injection gas from the Qusahwira CDS to 5 gas injection wells in Thamama A/B zone for pressure maintenance besides various supporting utilities and chemical injection facilities.

-

Constructing two new Water Injection Clusters (WIC-1 and WIC2) southwest of the Qusahwira CDS for water injection to oil wells in Thamama F zone for pressure maintenance including chemical injection facilities. Four wells shall be served from WIC-1 and one well from WIC-2.

-

Constructing a 20” production fluid transfer line from RDS-1 to the CDS

-

Constructing a 6” gas injection trunk line from the CDS to RDS-1for distribution to gas injection wells.

-

Constructing 22 flow lines from producing wells to RDS-1 and 2 flow lines directly to the CDS and constructing 5 gas injection flow lines from RDS-1 and 4 gas injection lines directly from the CDS.

-

Constructing a 14” Main Oil Line (MOL) to the CDS at Asab oil field.



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-

Providing expandability for future facilities at CDS to support 62.47 MBOPD crude oil production at Qusahwira by: 

Providing plot space for a third train of production separator, a third train of gas compression, gas dehydration & glycol regeneration, additional water separation tanks and additional produced water disposal pumps.



Providing utility systems for both phase-1 and phase-2

3.0

PURPOSE OF DOCUMENT This document describes the process at the new Central Degassing Station (CDS) that will collect production fluids, separate the oil, gas and water phases, and treat each phase as described below.

4.0

CENTRAL DEGASSING STATION

4.1

Well Head The production fluids flow from the well through the hydraulically actuated Subsurface Safety Valve (SSSV-XXXX-02) and Surface Safety Valve (SSV-XXXX-03) to the surface flow line gathering system and to the RDS. The SSSV is held open by hydraulic oil system pressure. In the event of a well head fire, a HP fusible plug on the hydraulic line opens, releasing hydraulic pressure, closing the valve and shutting in the well. The SSV is held open by hydraulic oil pressure and closes with loss of hydraulic system pressure on opening of one of four LP fusible plugs in event of fire, located near the well head. Also SSV closes based on High Pressure Pilot valve (HPPV) and Low Pressure Pilot valve (LPPV) set pressure. Hand switches on the local Well Head Control Panel open / close the SSSV and SSV. Hydraulic fluid is a self-contained system, pumped by a hydraulic fluid pump in the well head control panel. The pump and the panel are solar powered. The well head can be manually shut-in with Master Valve and the Wing Valve.

4.2

Inlet Facilities The Central Degassing Station (CDS) Separators receive produced fluids from RDS-1 and directly from two wells in the vicinity of the CDS. During phase 2 it will receive produced fluid from RDS-2 also. Well fluid from the two wells to CDS receive through two 6” flow lines. Each Flow line from well has a manual block valve at the CDS fence line Wells flowing directly to the CDS are combined through Multi-Selector Manifolds and directed to the Production and Test headers. All produced fluids enter the CDS Separators through the Production Manifold. a) Multi-Selector Manifolds Two Multi-Selector Manifolds (MSMs) (58-01-M-0201/M-0202) will be installed to accept Phase-1 production wells at the CDS. MSMs may be connected to a combination of Thamama-A/B or Thamama-F wells (Only Two Thamama-A/B wells Qw 020 and Qw 021 are directly connected to CDS in Phase-I). Qw 020 is connected to MSM, 58-01-M-0201 and Qw 021 is connected to 58-01-M-0202. Space is provided for third MSM, which shall be added in Phase-2. The MSM provides the ability to gather and combine the flow of produced fluids from up to seven (7) wells. Well flow lines are routed to the MSM assembly, where the well fluids are combined within the body of the MSM. The combined fluids flow out to the production



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header. Individual production headers from the MSMs are routed to the Production Manifold (M-0210). A rotating plug located within the body of the MSM can align with any of the seven inlet connections and divert the flow from an individual well to the test header through the test outlet. The test header flows through a multi-phase flow meter where flow measurements are taken and recorded before combining with other wells in the production header. Well testing is an automated procedure with the provision for local or remote operation. In the event that test meter is offline, the rotating plug is aligned with the blinded connection, so no fluid flows to the test outlet. The purpose of well testing is to obtain actual well performance data, including individual oil, water and gas rates, and to accumulate a database of well performance history. This data is used to evaluate reservoir performance against models allowing diagnosis of well performance issues and recommendation of remedial procedures. b) Production Headers, Test Headers and MPFMs During normal operation, fluids flow directly from each MSM to a 10” Production Header. The Production Headers are protected against overpressure by High Integrity Pressure Protection System (HIPPS), which consists of two shutdown valves, logic solver and three pressure transmitters (2 out of 3) installed at the Production Header. This is the sole means of overpressure protection. Operation of the HIPPS is controlled through the HIPPS Logic Solver with status indicated at the DCS. A pressure transmitter upstream of the HIPPS valves works in combination with the downstream pressure transmitters to determine the differential pressure across the HIPPS valves. This differential pressure (DPI) across HIPPS valves is used as a permissive to start logic against high differential pressure across the HIPPS valves. Produced fluid flowing from the MSMs test connection is periodically diverted, one well at a time, to one of two 4”Test Headers. Each Test Header includes a Multi-Phase Flow Meter (MPFM 58-01-FT-0201/FT-0202) that separately measures flow of the oil, gas and water phases and an auto-sampler for fluid analysis. The purpose of well testing is to obtain actual well performance data, including individual oil, water and gas rates, and to accumulate a database of well performance history. c) Pig Receivers and Production Manifolds Production fluids flow from RDS 1 through 20” transfer line to the CDS. A pig Receiver (5801-RP-1301) is installed at the end of 20” transfer line at CDS inlet in order to receive the pig launched from RDS-1 during the pigging operation. The CDS Inlet Manifold receives produced fluids from the RDS-1 20” transfer line and the Production Headers from CDS MSMs (M-0201/M-0202). There are two 24” production manifolds routed to two Production Separators in phase-1. Third production manifold shall be added in Phase-2. Provisions allow for future production tie-ins. Through a series of cross-over headers and motor operated valves in-coming produced fluids are routed through the Production Manifold to Production Separators (58-01-V-0301/V-0302) in Phases 1. Produced fluid from low pressure compressor suction drums (58-01-V-3112-01/ V-3122-01) and high pressure compressor suction drums (58-01-V-3113, V-3123) in Compression Trains 1 and 2 (Phase1), Closed Drain Drum (58-01-V-6701), Process Drain Drum (58-01-V-6702), Recovered Oil Collection Tank (58-01-V-1510) and Flare KO Drums (58-39-V-1911/V-1931/V-1941) are returned to the Separation Train production headers. 4.3

Production Separators From the inlet facilities, production fluids flow to the two Production Separators 58-01-V0301/V-0302 that separate gas and water from the oil. Space is provided for third



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Production Separator which shall be added in Phase-2. One stage of separation is provided at Qusahwira and the oil is pumped to ASAB for further treatment. Each of the Production Separators is sized to process 30 MBOPD of stock tank oil. Normally two separators are working in parallel. However, in case one of the separators is under maintenance, the other separator will be in operation at sustainable flow. The separator operating pressure is 3.5 barg. The operating temperature is 60 deg C in summer and 15 deg C in winter. The separator pressure is maintained at 3.5 barg through a back pressure control valve provided on the produced gas line going to gas compressor. There is provision of routing of the produced gas to flare in case of higher pressure of the Production Separator. The level control valves provided on produced water line in outlet of each Separator, controls the interface level of the Separators. The oil flows over a weir into the far end of the vessel. Level control is provided for the Oil. Refer to Reference 2, “Equipment Sizing Philosophy”. 4.4

Crude Oil Export System The crude oil export system consist of MOL booster pumps and MOL pumps MOL Booster Pumps The crude oil export pumps consist of two booster pumps ( one operating with a spare) dedicated to each production separator i.e. total four booster pumps (58-01-P-0901/P-0902 & 58-01-P-0903/P-0904) which feed to MOL pumps(58-01-P-1001/P-1002). Two additional Mol booster pumps shall be added in phase-2 corresponding to third production separator. The rated capacity is 230.2 m3/hr (at operating condition) per pump. The MOL booster pump takes suction from the respective production separator. A strainer is provided in suction of each MOL booster pump. The MOL booster pumps discharge to a common line going to MOL pumps suction. The flow control is provided for MOL Booster pump discharge which is reset by oil level control of the Separator from which MOL booster pump is taking suction. For minimum circulation flow an auto recycle valve is provided on discharge of each booster pump, which recycles the oil back to production separator from which the booster pump is taking suction. The MOL Booster pumps are provided with MOVs on discharge line. The MOV shall be linked to the start/stop logic of the MOL Booster pump. When the pump starts, the MOV shall open. When the pump stops, the MOV shall close MOL Pumps In Phase-1 there is one operating and one spare MOL pumps (58-01-P-1001/P-1002). Space is provided for a third pump which shall be added in Phase-2, so that two pumps will be operating and one will be spare. The rated capacity is 276.3 m3/hr (at operating condition) per MOL pump. The MOL pumps shall have four stages in phase-1 and 9 stage in Phase-2. Crude oil from the MOL Booster Pumps is pumped by the MOL Pumps through the MOL to the ASAB. One operating and one standby MOL basket strainers (58-01-ST1001/ST-1002) are provided in common pump discharge line. MOL pumps suction pressure (i.e pressure of common suction line of the MOL pumps) is controlled by the pressure control valve located downstream of MOL basket strainers in MOL pumps common discharge line. A selector switch is provided to select the PCV depending upon which MOL basket strainer is on-line. For minimum flow, fluid from the discharge of each of the MOL pumps is combined and recycled back to the MOL pump inlet line on pressure control. A MOL recycle cooler is provided on common minimum flow line to cool the recycled oil to 65 deg C before joining suction of the pumps.



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Corrosion inhibitor is injected in common suction line of MOL pump and biocide is injected in common discharge line of MOL pump The MOL pumps are provided with MOV on suction and discharge line The MOV shall be linked to the start/stop logic of the MOL pump. When the pump starts, the MOV shall open. When the pump stops, the MOV shall close. MOL Pig Launcher, Receiver and ASAB Connections The crude oil is pumped about 80 km from the Qusahwira CDS facility to the ASAB CDS 2nd Stage Inlet Manifold. The pipeline system includes a MOL Launcher (58-01-LP-1303) at Qusahwira, a Pig Receiver at ASAB (14-01-RP-1311) and a MOL back pressure control station at the ASAB 2nd Stage Inlet Manifold. Backpressure on the MOL is controlled at the 2nd Stage Feed Backpressure Control Station downstream of the Pig Receiver. An MOL Pig Launcher is provided at CDS on the export pipeline to Asab to allow for periodic pigging operations, while a pig receiver is provided at ASAB. 4.5

Produced Water Handling A produced water treatment and disposal system is required to handle the produced water at the CDS. Water produced with the reservoir fluids is separated from the crude oil in the Production Separators. The water effluent is drawn from the Production Separators on interface level control by a level control valve and combined into a common header which is then routed to the Water Separation Tanks. In Phase-1 there are two Water Separation Tanks (58-01-T2401/T-2402). Space is provided for three more tanks which shall be added in phase-2. Scale inhibitor, deoiler, and biocide are injected upstream of Water Separation Tank in common line. There is also a provision of intermittent dosing of biocide in upstream of individual water separation tank. The water separation tanks are blanketed with fuel gas and maintained at pressure of 0.02 barg and vented to vapor recovery header. Hydrocarbon vapor may also degas from the water. The Water Separation Tanks are also equipped with internal oil skimmers to recover oil and return it to the Production Separators for reprocessing via the Recovered Oil Collection Tank (58-01-V-1510). The Oil, forms a layer on the water, overflows a weir into the oil compartment. Oil level in the separator oil compartment is controlled by gap acting level controller, with high and low alarms, which opens the level control valve in the oil outlet line on high level and closes on low level. The Recovered Oil Collection Tank (58-01-V-1510) is underground and is blanketed with fuel gas, which is returned to the process through the Vapor Recovery Compressor. The Recovered Oil Collection Tank operating pressure is 0.018 barg. The Recovered Oil Collection Tank (58-01-V-1510) is pumped out by the submersible tank-mounted Recovered Oil Return Pumps that operate in lead / lag mode. One pump pumps starts on high level with the second coming on-line should level continue to rise in the drum. The contents of the drum are pumped to the inlet of the production separators Oil content of the disposal water is limited to 1000 ppm. In phase-1 water from the Water Separation Tanks flows by gravity through a common line to the two Disposal Water Tanks (58-01-T-2404/T-2405) which provide surge volume for the system. Space is provided for an additional Disposal Water Tank which shall be added in phase-2. The Disposal Water Tanks are blanketed with fuel gas and maintained at pressure of 0.02 barg and vented to vapor recovery header.



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Water from Disposal Water tanks (58-01-T-2404/T-2405) is then pumped through Disposal Water pumps (58-01-P-2402-01/02/03/04/05) by a common line to the five Water Disposal Wells In phase-1 there are four operating and one spare Disposal Water Pump and additional five pumps shall be added in Phase-2. The pumps combined flow is controlled by level control on disposal water tanks. An auto recycle valve is provided on discharge of each pump which is tied together with a common recycle header returning minimum flow recycles to the disposal water tank. Scale inhibitor is also injected in common suction line of Disposal Water Pumps. In phase-1 there are five produced water disposal wells. Flow to wells from the disposal well header is balanced by manually adjusting a valve located near the well head 4.6

Gas Compression and Distribution All gas produced at the Qusahwira facility shall be re-injected to maintain pressure on the Zone A/B field during Phase-1. The final pressure at the injection gas wells is 220.6 barg (3200 psig). The Produced gas from Production Separators flows on back pressure control to a common header to a spared reciprocating compressor train

4.6.1

Gas Compressor: During Phase-1, the produced gas from Production separator is compressed in four stage spared reciprocating compressor. Induced draft air coolers are used for interstage cooling. The temperature control scheme first includes a variable speed control of cooler fan motors followed by louvers control and finally outlet temperature is controlled by cooler by-pass flow control. Each stage has a suction scrubber. The outlet of stage 2 has a discharge scrubber also. The suction pressure of each stage is controlled by a spillback line from discharge of the corresponding stage of the compressor. The two low pressure stages compress wet gas. The gas is dehydrated between stages 2 and 3 by counter current contact with tri-ethylene glycol in a trayed contactor. During Phase-1, two 100% reciprocating compression trains will operate with dedicated glycol contactors sharing a common regeneration unit. Ist Stage Compression Produced gas from Separator and recovered vapors from Vapor Recovery Unit and Glycol Flash Drum are sent to Ist stage suction drum (Train-1: 58-01-V-3111, Train-2: 58-01-V3121). The knocked out liquid is sent to Process Drain Drum (58-01-V-6702). Level of the suction drum is controlled by gap action level controller, with high and low alarms, which opens the level control valve on the liquid drain line on high level and closes on low level. Gas from Ist stage suction drum flows through the one operating and one standby Ist Stage Suction Strainers (Train-1: 58-01-ST-3111-01/02, Train-2: 58-01-ST-3121-01/02),to 1st Stage Gas Compressor (Train-1: 58-01-K-3111, Train-2: 58-01-K-3121). The suction pressure is controlled by a control valve on spillback line from discharge of second stage suction drum. The gas is compressed from 1.5 barg to 8.8 barg and than cools in 1st Stage Cooler (Train-1: 58-01-E-3111, Train-2: 58-01-E-3121). The outlet temperature of cooler is 65 deg C in summer and 60 deg C in winter. 2nd Stage Compression Produced gas from 1st Stage Cooler (Train-1: 58-01-E-3111, Train-2: 58-01-E-3121) along with knocked out liquid from 2nd stage discharge drum and 3rd stage suction drum enters 2nd stage suction drum (Train-1: 58-01-V-3112-01, Train-2: 58-01-V-3122-01). The knocked out liquid is sent to Production separator. Level of the suction drum is controlled by gap action level controller, with high and low alarms, which opens the level control valve on the liquid drain line on high level and closes on low level.



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Gas from 2nd stage suction drum flows through one operating and one standby 2nd Stage Suction Strainers (Train-1: 58-01-ST-3112-01/02, Train-2: 58-01-ST-3122-01/02),to 2nd Stage Gas Compressor (Train-1: 58-01-K-3112, Train-2: 58-01-K-3122). The suction pressure is controlled by a control valve on spillback line from discharge of 2nd stage discharge drum. The gas is compressed from 8.1 barg to 35.9 barg and than cools in 2nd Stage Cooler (Train-1: 58-01-E-3112, Train-2: 58-01-E-3122). The outlet temperature of cooler is 65 deg C in summer and 60 deg C in winter. The gas then enters a 2nd stage discharge drum (Train-1: 58-01-V-3112-02, Train-2: 58-01-V-3122-02). The knocked out liquid is sent to 2nd stage suction drum inlet. Level of the 2nd stage discharge drum is also controlled by gap action level controller, with high and low alarms, which opens the level control valve on the liquid drain line on high level and closes on low level The gas is dehydrated between stages 2 and 3 by counter current contact with tri-ethylene glycol in a trayed contactor which is described under Gas dehydration section 3rd Stage Compression Gas from the Glycol Contactor (Train-1: 58-01-C-311-01, Train-2: 58-01-E-3111-02) enters 3rd stage suction drum (Train-1: 58-01-V-3113, Train-2: 58-01-V-3123). The knocked out liquid is sent to 2nd stage suction drum inlet. Level of the suction drum is controlled by gap action level controller, with high and low alarms, which opens the level control valve on the liquid drain line on high level and closes on low level. Gas from 3rd stage suction drum flows through the one operating and one standby 3rd Stage Suction Strainers (Train-1: 58-01-ST-3113-01/02, Train-2: 58-01-ST-3123-01/02),to 3rd Stage Gas Compressor (Train-1: 58-01-K-3113, Train-2: 58-01-K-3123). The suction pressure is controlled by a control valve on spillback line from discharge of 3rd Stage Cooler. The gas is compressed from 33.2 barg to 89 barg and than cools in 3rd Stage Cooler (Train-1: 58-01-E-3113, Train-2: 58-01-E-3123). The outlet temperature of cooler is 65 deg C in summer and 60 deg C in winter. 4th Stage Compression Produced gas from 3rd Stage Cooler (Train-1: 58-01-E-3113, Train-2: 58-01-E-3123 enters 4th stage suction drum (Train-1: 58-01-V-3114, Train-2: 58-01-V-3124). The knocked out liquid is sent to 3rd stage suction drum inlet. Level of the suction drum is controlled by gap action level controller, with high and low alarms, which opens the level control valve on the liquid drain line on high level and closes on low level. Gas from 4th stage suction drum flows through the one operating and one standby 4th Stage Suction Strainers (Train-1: 58-01-ST-3114-01/02, Train-2: 58-01-ST-3124-01/02),to 4th Stage Gas Compressor (Train-1: 58-01-K-3114, Train-2: 58-01-K-3124). The suction pressure is controlled by a control valve on spillback line from discharge of 4th Stage Cooler. The gas is compressed from 88.3 barg to 249.6 barg and than cools in 4th Stage Cooler (Train-1: 58-01-E-3113, Train-2: 58-01-E-3123). The outlet temperature of cooler is 65 deg C in summer and 60 deg C in winter. For Phase-2, a third train using a centrifugal compressor will be added to handle all of the produced gas, which will be compressed, dehydrated and then compressed to injection pressure, as in Phase-1. Compressor trains 1 and 2 will then serve as partial spare units. Train 3 will have a dedicated glycol contactor and regenerator package. There will not be enough produced gas to meet gas injection requirements. Therefore, gas will be imported from GASCO Asab to make up the difference. This gas will be added to Train 3 downstream of the Glycol Contactor but upstream of the stage 3 suction scrubber. Lean gas may be added to Train- 1 & 2 in case Train-3 is down. Compressor vendor’s response is provided as an Annexure-1. The gas from Asab will have a maximum concentration of



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250 ppm H2S. It is not intended that a reciprocating compressor will operate with the centrifugal compressor in Phase-2. 4.6.2

Injection Gas distribution The compressed gas is distributed to the CDS gas distribution system and RDS-1. The gas is transferred to RDS-1 by a 6” gas injection pipeline. An Injection Gas Pig Launcher (5801-LP-3902) is provided at CDS on the export pipeline to RDS-1 to allow for periodic pigging operations.

In CDS Gas from the Injection Gas Header is distributed by 3” branch lines to individual injection wells. During phase-1, there will be 4 gas injection wells in CDS. 4.7

Gas Dehydration Between Stages 2 and 3 of each compression train, the produced gas is dehydrated by counter current contact with lean tri-ethylene glycol (TEG) in a 12-Trayed Glycol Contactor (Train-1: 58-01-C-3111-01, Train-2: 58-01-C-3111-02) drying the gas to 3 lbs H2O/MMSCF gas. During Phase-1, two 100% reciprocating compression trains will operate with dedicated glycol contactors sharing a common regeneration unit. The gas enters the bottom of the Glycol Contactor and contacts the TEG across 12 trays. Cooled lean TEG enters the top of the contactor. A dew point analyser is provided at outlet of the contactor. Normally gas flows from the contactor directly to the 3rd Stage Suction Drum. On increasing pressure in the contactor gas is vented to the HP Flare on pressure control. Rich TEG is drawn off on level control from the trap-out tray below the bottom-most contacting tray of Glycol Contactor. The rich TEG then flows to the Reflux Condenser Coil (58-01-E-3116-01) of the regeneration system (58-01-U-3116-01), where it acts as the cooling medium above the Still Column (58-01-C-3116-01). The preheated rich TEG then enters the Glycol Flash Drum (58-01-V-3116-01). Vapor from the flash drum flows back to the inlet of the LP compression trains. After the flash drum, the TEG is filtered through the spared Cartridge TEG Filters (58-01-S3116-01/02) and the Charcoal TEG Filter (58-01-S-3116-03). The rich TEG is further preheated in the TEG Lean / Rich Exchangers (58-01-E-3116-02/03/08) where it recovers heat from the lean TEG. Additional lean / rich heat exchange occurs in the Coil Surge Drum Cooler (58-01-E-3116-04). The rich TEG then enters the packed Still Column (58-01-C-3116-01) where hot gas strips water and hydrocarbons from the TEG. The overhead gas passes through the Reflux Condenser Cooler (58-01-E-3116-01) and then flows to the Vapor Recovery Unit. The partially stripped TEG enters the TEG Reboiler (58-01-V-3116-02) below the Still Column where the TEG Thyristor (58-01-E-3116-05) provides the heat input. The TEG is further stripped in the packed Stripping Column (58-01-C-3116-02) below the reboiler before entering the Coil Surge Drum Cooler (58-01-E-3116-04). The lean TEG is cooled in the TEG Lean / Rich Exchangers (58-01-E-3116-02/03/08). Lean TEG is pumped by TEG Circulation Pumps (58-01-P-3116-01/02/03) and air cooled in Lean TEG Coolers (58-01-E3116-06/07), and returned to the top of the Glycol Contactor (Train-1: 58-01-C-3111-01, Train-2: 58-01-C-3111-02). The glycol regeneration area has a dedicated Glycol Drain Drum (58-01-V-3101) and submersible Glycol Drain Pumps (58-01-P-3101-01/02), so that any TEG drained from equipment and piping can be handled separately form the Process and Closed Drains and recovered. The Glycol Drain Drum (58-01-V-3101) is underground and is blanketed with fuel gas, which is returned to the process through the Vapor Recovery Compressor. The



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Glycol Drain Drum operating pressure is 0.2 barg. The Glycol drain pumps operate in lead/lag mode.The contents of the drum are pumped to Glycol Flash drum through a Glycol drain filter 58-01-S-3101. 4.8

Chemical Injection Systems Chemical Injection Packages will be provided at the CDS for Demulsifier (58-01-U-6201), Corrosion Inhibitor (58-01-U-6202), Biocide (58-01-U-6203), Water Deoiler (58-01U-6205) and Scale Inhibitor (58-01-U-6206). Demulsifier is injected upstream of each of the Production Separator with a spared metering pump. The Corrosion Inhibitor Package consists of HP header which is pressurized with an operating and a spare HP corrosion inhibitor injection pump. This HP header supplies corrosion inhibitor to production headers leaving each MSM and test header. Additionally, a LP metering pumps with a spare supplies corrosion inhibitor to the production manifolds, upstream of each Production Separator and at upstream of the MOL Pumps. A common test chemical storage vessel is provided which is hard piped to the demulsifier and corrosion inhibitor pumps for the testing of new chemicals. Biocide-1 is continuously injected upstream of the Water Separation Tanks with one set of metering pumps. Another metering pump is provided to alternately inject biocide-1 & biocide-2 at the upstream of each Water Separation Tank to provide an intermittent dosing of biocide to one tank at a time. A second set of metering pumps (one operating and one spare) alternately inject biocide-1 & biocide-2 into the MOL line just upstream of the MOL Pig Launcher LP-1303. Water deoiler and Scale inhibitor are injected upstream of the Water Separation Tanks with metering pumps. Scale inhibitor is also injected in common suction line of Disposal Water Pumps. Each package has a spare for the metering pumps. The chemical storage vessels are filled from drums using portable pneumatic drum pumps. The chemical storage vessels have a 7 day capacity at maximum injection rates. Biocide dosing vessels are provided with 7 day capacity for continuous dosing and 24 hour capacity for intermittent dosing. A low level alarm is provided giving 24-hour notice to refill. The injection metering pumps are gravity fed from the storage vessels. A potable water connection is provided at injection pump suctions for system flushing and calibration. For design chemical dosing rates are based on chemical concentration in liquid phase of 10 ppmw for corrosion inhibitor, 20 ppmw for demulsifier, 8 ppmw for scale inhibitor, 20 ppmw for continuous biocide, 500 ppmw for intermittent biocide and 20 ppmw for deoiler. For each chemical injection package, dedicated chemical drain pit/vessel is provided. For scale inhibitor, biocide & deoiler lined RCC pits are provided for the purpose. Whereas being flammable in nature corrosion inhibitor & demulsifier packages are provided with CS vessels. Drains from chemical system such as chemical storage tank drain, chemical storage tank overflow, chemical skid base plate drains etc are connected to a chemical drain pit/vessel. Chemical drain pit/vessel are installed below grade in order to allow gravity draining.

4.9

Vapor Recovery The Vapor Recovery System collects low pressure gases used to purge and blanket low pressure tanks and drain drums as well as the off gas from the glycol regeneration packages. The system discharges the recovered gas into the suction line of the compression trains. One Vapor Recovery System is sized to handle the gas from both the phase-1 and phase-2. Tie-ins for a second Vapor Recovery System are provided should additional capacity be required in the future.



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The Vapor Recovery Compressor is a Liquid Ring type requiring a 3 phase separator, water recycle cooler and a water make up tank. The VRC Discharge 3-Phase Separator separates oil, gas, and water. The oil flows to the Process Drain. The gas flows to the common header feeding LP Compression Trains. The water is cooled in the VRC cooler and returned to the compressor. In the event that the compressor shuts down or is not operating, fast acting blow down valve divert the inlet gas to the Tank Flare System for disposal. A pressure control valve also diverts gas to the Tank Flare System if the suction pressure of the Compressor gets too high. Dedicated recycle lines are used to maintain positive pressure in the suction line. The Vapor Recovery Package (58-01-U-3801) is comprised of the following equipment:

4.10

•

Vapor Recovery Compressor (58-01-K-3801).

•

Mechanical Seal Pot (58-01-V-3802).

•

VRC Cooler (58-01-E-3801).

•

VRC Discharge 3-Phase Separator (58-01-V-3801).

Fuel Gas Fuel Gas is provided throughout the plant from the Fuel Gas Distribution System. The system takes gas from the Glycol Contactor discharge line and sends the same to Fuel Gas Scrubber before distributing it to the plant. The Fuel Gas Scrubber (58-01-V-3201) is maintained at 3.0 - 3.5 barg by a pressure control on fuel gas supply line. When the compressed gas from Glycol Contactor is unavailable, the gas will be taken from the Production Separators overhead. Provision is made to supply lean gas from GASCO to the inlet of the fuel gas scrubber in Phase-2. Fuel gas distribution header supplying fuel gas for blanketing is provided with an automatic nitrogen backup actuated in case of low fuel gas pressure. Propane cylinders are also provisioned to be used during startup and as automatic back up for flare pilots only when fuel gas system is not available. The propane will be used for limited period for operator to take necessary action.

4.11 Flare Systems 4.11.1 HP, HP Cold and HP Spare Systems The HP, HP Cold and HP Spare Flare Systems are installed to vent gases that are not contained by the process or recycled through the vapor recovery compressor. The HP Spare Flare is a common spare for both the HP and the HP Cold Flares. The flare systems include the following equipment: 

HP Flare Stack (58-39-FL-1921).



HP Flare Knock-Out Drum (58-39-V-1921).



HP Flare Knock-Out Drum Pumps (58-39-P-1921-01/02).

The HP cold flare system includes the following equipments: 

HP Cold Flare Stack (58-39-FL-1911).



HP Cold Flare Knock-Out Drum (58-39-V-1911).



HP Cold Flare Knock-Out Drum Pumps (58-39-P-1911-01/02).

The HP spare flare system includes the following equipments: 

HP Spare Flare Stack (58-39-FL-1931).



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

HP Spare Flare Knock-Out Drum (58-39-V-1931).



HP Spare Flare Knock-Out Drum Pumps (58-39-P-1931-01/02).

The Flare Drain system includes the following equipments: 

Flare Drain Drum (58-39-V-6701).



Flare Drain Pumps (58-39-P-6701-01/02).

Lower pressure and wet areas discharge into the HP Flare Header and high pressure dry areas discharge to the HP Cold Flare Header. The HP Spare Flare can be attached to either header through interlocked valves such that each header must discharge into an appropriate flare system, and that the one flare system not in use must be closed off from the process. The flare systems are for emergency relief and shutdowns and have continuously lit pilots and flame detectors. The design flare flow rate for the HP flare is a case when full diversion of the produced gas from production separator with a simultaneous blowdown of the Train-3 LP compression area and Glycol Contactor occurs. The controlling case for the HP Cold Flare header occurs during a simultaneous blow down of the third and fourth stages of the reciprocating compressor train-1 (or reciprocating compressor train-2) and blow down of the third and fourth stages of the centrifugal compressor train-3. Flare Knock-Out Drums are above ground and are provided with two centrifugal pumps operating in lead / lag mode. One pump starts on high level, followed by the second if the level continues to rise in the drum. Liquids accumulated in the Flare KO Drum are pumped into the inlet manifold. The Flare KO Drum Pump drains and instrumentation drain lines are locally drained to the Flare Drain Drum. The contents of Flare Drain Drum are pumped to the Closed Drain Drum. The flare header is purged continuously with nitrogen with fuel gas backup while in service. Flare pilot fuel gas is supplied from the fuel gas system with propane as back-up. A knockout standpipe is provided for the fuel gas upstream of the fuel gas pressure regulator and the flame front generator. The liquid will drain through a trap drain valve back to the respective flare knockout drum. 4.11.2 Tank Flare System Tank Flare System is installed to vent low pressure gases in the event that the Vapor Recovery Compressor is unavailable or is unable to maintain a sufficiently low suction pressure. The system has a full installed spare. The flare system includes the following equipment: •

Tank Flare Stack (58-01-FL-1941).

•

Tank Flare Knock-Out Drum (58-01-V-1941).

•

Tank Flare Knock-Out Drum Pumps (58-01-P-1941-01/02).

•

Spare Tank Flare Stack (58-01-FL-1951).

•

Spare Tank Flare Knock-Out Drum (58-01-V-1951).

•

Spare Tank Flare Knock-Out Drum Pumps (58-01-P-1951-01/02).



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The Tank Flare System is designed as a back up to the Vapor Recovery System and is sized to handle the full capacity of the Vapor Recovery System should it not be available. The Tank Flare System is for emergency relief and shutdowns and has a continuously lit pilot and flame detector. Flare Knock-Out Drums are above ground and are provided with two centrifugal pumps operating in lead / lag mode. One pump pumps down on high level with the second coming on-line should level continue to rise in the drum. Liquids accumulated in the Flare KO Drum are pumped into the Production manifold. Flare KO Drum Pump drains are locally drained to the Flare Drain Drum. The flare header is purged continuously with nitrogen with fuel gas backup while in service. Flare pilot fuel gas is supplied from the fuel gas system with propane as back-up. A knockout standpipe is provided for the fuel gas upstream of the fuel gas pressure regulator and the flame front generator. The liquid will drain through a trap drain valve back to the respective flare knockout drum. Below in Table 3-1 are the HSE Requirements for allowable flare radiation and dispersion. 4.11.3 Flare Drain System A flare drain system is provided to drain vessels and piping in flare area for maintenance operations. The flare drain system includes the following equipment: •

Flare Drain Drum (58-39-V-6701).

•

Flare Drain Pumps (58-39-P-6701-01/02).

The flare drain header system is underground and purged with nitrogen, with fuel gas backup. The flare Drain Drum is floating on tank flare. The flare Drain Drum is installed below grade and is pumped out by the submersible tankmounted flare Drain Pumps that operate in lead / lag mode. One pump pumps starts on high level with the second coming on-line should level continue to rise in the drum. The contents of the drum are normally pumped to the closed drain header. 4.12 Process and Closed Drains 4.12.1 Closed Drain System A closed drain system is provided to drain vessels and piping for maintenance operations. The closed drain system includes the following equipment: •

Closed Drain Drum (58-01-V-6701).

•

Closed Drain Drum Pumps (58-01-P-6701-01/02).

The closed drain header system is underground and purged with fuel gas. The Closed Drain Drum is blanketed with fuel gas, which is returned to the process through the Vapor Recovery Compressor. The Closed Drain Drum operating pressure is 0.2 barg. The Closed Drain Drum is pumped out by the submersible tank-mounted Closed Drain Pumps that operate in lead / lag mode. One pump pumps starts on high level with the second coming on-line should level continue to rise in the drum. The contents of the drum are normally pumped to the inlet of the production separators. If the Water Separation Tanks or Water Disposal Tanks have been drained to the drum, then the contents may be pumped to the Water Separation Tanks instead. Closed Drain Drum is installed below grade in order to allow gravity draining from the flow lines into the drum.



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4.12.2 Process Drain System The Process Drain System is installed to accept online waste streams from the process for recycling back to the production separators. The process drain system includes the following equipment: •

Process Drain Drum (58-01V-6702).

•

Process Drain Drum Pumps (58-01-P-6702-01/02).

Process drains are routed to the Process Drain header that feeds the Process Drain Drum. A dedicated drain header is provided for each piping class. The system is operated under a fuel gas blanket, and vented to the vapor recovery header. The Process Drain Drum operating pressure is 0.2 barg. The Process Drain Drum is pumped out by the submersible tank-mounted Process Drain Pumps that operate in lead / lag mode. One pump starts on high level, with the second coming on-line should level continue to rise in the drum. The contents of the drum are pumped to the production separators. The Process Drain Drum is installed below grade in order to allow gravity draining from the flow lines into the drum. 4.12.3 Tundish System A Tundish System is provided to collect hydrocarbons from drip pans at the pig launchers and receivers, compressors and pumps and the diesel supply system. Collected hydrocarbon drains by gravity to a below ground atmospheric tank i.e. Tundish Drain Sump (58-01-V-6703) and then pumped to the Closed Drain Header by submersible tank mounted Tundish Drain Pump (58-01-P-6703). One warehouse spare pump without motor is also provided. 4.13

Compressed Air System A Compressed Air System is provided for instrument air, plant air, and nitrogen generation. The Air Compressors and Dryer Package, includes the following equipment items: •

Air Compressors (58-01-K-6101/K-6102/K-6103/K-6104).

The Air Compressor configuration is 2 lead compressor, one lag compressor and one standby. •

Instrument Air Dryer System (58-01-D-6101-01/02).

The Instrument air dryer configuration is two duplex desiccant dryers, each dryer shall be have two columns, one operating and other under regeneration. These are heatless type dryers with automatic regeneration by purge air. Additionally, the air compression system includes the following equipment items: •

Instrument Air Receiver (58-01-V-6111).

•

Plant Air Receiver (58-01-V-6110).

In addition to supplying the CDS instrument air requirements the Compressed Air System supplies instrument air to the CDS Nitrogen Generation System as feed, the Flare Flame Front Generators and the utility stations. The instrument air dryer is a two column system, one of which is in drying mode while the other is in regeneration. A second air dryer package is provided as a spare. Instrument air is supplied at 9.5 barg max, depending on the pressure drop through the dryer, but not less than 4.2 barg at Instrument air dryer outlet. The Air Compressors will operate with two operating as lead, one operating as lag, and one as a spare, each with a rated capacity of 1500 Nm3/h. The priority of compressed



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air supply is first to the instrument air headers followed by nitrogen generation with the plant air system being the lowest priority. 4.14

Nitrogen Generation System A Nitrogen Generation System with two trains is provided for the CDS. Generation Packages, U-6911/21, includes the following equipment items:

The Nitrogen

•

Coalescing Filters (58-01-S-6911-01/02/03/04/05/06/S-6921-01/02/03/04/05/06).

•

Membrane Separators (58-01-S-6912/-01/02/03/04/S-6922-01/02/03/04).

•

Electric Heater (58-01-H-6911-01/ H-6921-01).

Additionally, the Nitrogen Generation System includes the following equipment items: •

Nitrogen Receiver (V-6901).

The Nitrogen Generation Package is supplied with air at about 9.0 barg (max) from the Compressed Air System. Nitrogen is supplied at 8.0 (max) barg (at nitrogen package B/L), but not less than 4.2 barg, with a purity of 98% minimum. Nitrogen from the Nitrogen Receiver provides purge and seal gas to the compressors, HP Flare Header, HP Cold Flare Header, Tank Flare Header, and Utility Stations inside the CDS. The Nitrogen Generation Packages each have a rated capacity of 595 Nm3/hr. 4.15

Diesel Fuel The Diesel Fuel System is provided for the CDS to supply diesel fuel to the Emergency Generator and Firewater Pump P-5101. The system contains the following equipment items: •

Diesel Storage Tank (58-01-T-6301)

•

One operating and one standby Diesel Transfer Pump (58-01-P-6301-01/02)

•

Diesel Fine Filter (58-01-S-6301)

A truck connection is provided on the Diesel Storage Tank to allow a tank truck supply of diesel fuel. The transfer pumps supply diesel to the Firewater Pump Fuel Day Tank and the Emergency Generator Day Tank via the Diesel Fine Filter. These pumps are provided with a minimum flow circulation line. The transfer pump trips in the event of low level in tank. In addition there is a low and high level alarm in DCS indicating for tank refill or pump trip. 4.16

Emergency Diesel Generator The emergency diesel generator is not working during normal operation. It shall start on low voltage in case the normal power supply fails.

4.17

Potable Water System Potable water system consist of Potable Water Generation System Potable Water Storage and Distribution

4.17.1 Potable Water Generation System A Potable Water Generation System shall be provided at the CDS. Feed water to the Potable Water Treatment Package is supplied from dedicated water supply wells with submersible pumps (supplied by ADCO). The package shall produce 1000 m3/day of potable water. The Package shall consist of Pre-Treatment section for treatment of Raw Water received from the RO Feed Water Tanks, a Two-Stage Filtration system, High Pressure RO feed Pumps and RO skids to produce potable water quality as per ADNOC Specifications for Drinking Water. The potable water shall fill the potable water tanks (58-



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01-T-2303/04) which are sized for a combined works capacity of 3 days (1-1/2 days per tank) at CDS. A tanker connection is also provided outside the CDS fence for filling the storage tanks. Accommodations will be provided with additional potable water storage. The potable water pumps shall supply water to the CDS water supply system and the dedicated pumps are provided to the pipeline going to the accommodations area. The Reject Water from the Potable Water Treatment package shall be sent to the RO Reject Water Tank and then pumped into a disposal well with the RO Reject Water Pump. 4.17.2 Potable Water Storage and Distribution Inlet Facility Inlet for potable water is provided from ADWEA by a dedicated line controlled by MOV’s to potable water storage tanks. Apart from this provisions are also kept for filling the storage tanks from:

Tanker, for which a coupling connection is provided with a ball valve and a check valve.



Potable Water Treatment Package, for which a dedicated line from potable water treatment package (refer section below) to potable water storage tanks is provided with MOV’s.

Storage Potable water is stored in two numbers potable water tanks (T-2303 & T-2304) having a capacity of 1500 m3 each. Each tank is provided with appropriate appurtenances for maintenance of tank and proper functioning of the system. Pumping and Distribution Potable water pumps consist of four numbers of pumps (2 operating and 2 standbys). These pumps draw suction from a common suction header, which receives water from both the tanks and pumps it directly to the distribution network. Two number pumps, one working and one standby (P-2303-01 & P-2303-02) of rated capacity 25m3/hr and discharge pressure of 6.213 barg are provided for potable water distribution to the following: 

Safety Shower/ Eye wash unit



Control Room



Sub Station



Entry Building



Utility Stations



Potable water makeup drum



Pig Receivers



To MOL Launcher



Injection Gas Station

Apart from these, connections are also provided from these pumps for 

Controlling the pumps flow by level control on potable water storage tanks



Makeup water line to fire water tanks with shut down valve.



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

Auto recycling of minimum flow of pumps back to potable water tank by means of flow control valve

Two number dedicated pumps, one working and one standby (P-2303-03 & P-2303-04) of rated capacity 70m3/hr and discharge pressure of 12.6 barg are provided for potable water supply to the following:

5.0



Camp Accommodation



Workshop



Fire Station



Administration Building



Laboratory

REFERENCES 1. “Process Design Basis: Qusahwira”, Project Document No. A049-000-02-41-DB-1001, ADCO Document No. 58-99-91-1625.

6.0

2.

“Equipment Sizing Philosophy”, EIL Document No. A049-000-02-41-DP-1004, ADCO Document No. 58-99-91-1605.

3.

“Process Description – Qusahwira Remote Degassing Stations”, Project Document No A049-011-02-41-PD-1001., ADCO Document No. 58-11-91-1601.

ANNEXURES

1. Compressor vendor confirmation for operability of reciprocating compressor with lean gas.



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Annexure-1 Sheet 1 of 4

Annexure-1 Sheet 2 of 4

Annexure -1 Sheet 3 of 4 TM0208 Injection Gas Compressor Item No; 58-01-K-3111-3114 and 58-01-K-3121-3124

NPCC/ADCO

Study of Parallel Operation

Lean gas (MW=18.37) 10MMSCFD (9155kg/H)

Case-1A REQUIRED CAPACITY From Separator Saturated gas

5MMSCFD

→

1st stage

2nd stage

→ Contactor GDV

9.29MMSCFD 14067 30.4

9.71MMSCFD 15656 32.34

50% 2.49 58.9 9.8 134 613 2510

50% 9.1 53.3 36.9 129 600

4619kg/H MFGR.'S RATED CAPACITY

MMSCFD kg/H

MOL.. WT. LOAD SUC. PRESSURE @PUL.SUPP. SUC. TEMPERATURE DIS. PRESSURE @PUL.SUPP. DIS. TEMPERATURE kW/STAGE TOTAL kW

BARA ℃ BARA ℃

→

11037

From Separator Saturated gas MFGR.'S RATED CAPACITY

MMSCFD kg/H


BARA ℃ BARA ℃

3rd stage Lean gas 10MMSCFD 16.81MMSCFD + 9155 20192 24.1 100% 34.16 64.2 90 132 717

→ 4th stage

15MMSCFD

12.58MMSCFD 15112 24.1 100% 88.3 64.8 250.6 144 580

Lean gas (MW=18.37) 10MMSCFD (9155kg/H)

Case-1B REQUIRED CAPACITY

15MMSCFD

5MMSCFD

→

1st stage

2nd stage

9.29MMSCFD 14067 30.4

9.71MMSCFD 15656 32.34

50% 2.49 58.9 9.8 134 613 2516

50% 9.1 53.3 36.9 129 600

→ Contactor GDV

→

MES's Confirmation (2011/5/27) Injection gas compressor will be able to operate at Lean gas case (Case 1 and Case-2) as above caluculation result.

15MMSCFD 3rd stage Lean gas 7.19MMSCFD 16.87MMSCFD + 6583 22239 26.45 100% 34.16 64.2 90 129 700

→ 4th stage

13.76MMSCFD 18137 26.45 100% 88.3 64.8 250.6 139 603

15MMSCFD

Annexure - 1 Sheet 4 of 4

TM0208 Injection Gas Compressor

NPCC/ADCO

Study of Parallel Operation

Lean gas (MW=18.37) 6.5MMSCFD (5951kg/H)

Case-2 REQUIRED CAPACITY From Separator Saturated gas

8.5MMSCFD

→

1st stage

2nd stage

→ Contactor GDV 15385kg/H

MFGR.'S RATED CAPACITY

MMSCFD kg/H


BARA ℃ BARA ℃

18.81MMSCFD 28488 30.4

19.98MMSCFD 32190 32.34

100% 2.49 58.9 9.8 131 1242 3785

100% 9.1 53.3 36.9 127 1236

→

16805

15MMSCFD 3rd stage Lean gas 6.5MMSCFD 16.89MMSCFD + 5951 22756 27.03 100% 34.16 64.2 90 128 696

→ 4th stage

14.16MMSCFD 19073 27.03 100% 88.3 64.8 250.6 138 611

15MMSCFD

Process and Utility Description CDS

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