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CEP-Subsea Pipeline -Gas Plant Process StudyGMEC – BEN WEI M.SC. P.ENG.
Purpose of Hysys Process Simulation Study1.0 To predict the production rates
2.0 To provide technical support to operations
3.0 To forecast the future production yields at gas plant
4.0 To estimate the gas shrinkage for future gas field development
5.0 To identify the bottle-necks for gas flow rate and composition changes
6.0 To predetermine process flow and major equipment's change requirements
Process Study Basis1.0 Six Well Stream Compositions and flow rates from LW 3-1
2.0 Reservoir operating conditions in typical six years of 2017, 2018, 2020, 2023, 2026 & 2029
3.0 The process model of matching 2014 operating conditions of CEP-Subsea pipeline- gas plant
4.0 Existing Process Flow Diagrams of Central Platform, Subsea Pipeline& Gas Processing Facilities
5.0 The built model based on operating parameters of Daily Production Report in October 2014
6.0 Fuel gas consumption of Daily Production Report in Oct. 2014
7.0 Existing Equipment Capacity.
Process Study Methodologies1.0 Built the HYSYS model based on the existing facilities and operating conditions of Oct 2014
2.0 Prorated the fuel gas consumption of 2014 based on flow rates of six typical well streams
3.0 Performed process HYSYS simulation to obtain commercial production yields.
4.0 Adjusted TEG, MEG for gas and condensate dehydration conditions at CEP to obtain hydro-formation point to meet the subsea pipeline requirement – 15°C.
5.0 Revised propane recirculation flow rate to meet the condensate stabilization requirements
6.0 Recomputed amine recirculation flow rate to meet the CO2 removal requirements
7.0 Adjusted turbo- Expander refrigeration and deep cuts fractionation to produce commercial sales gas, propane, butane, as well as condensate hydrocarbon.
Unit Flow Diagram (UFD)
Central Platform Gas Plant Terminal Facilities
261 Km- 30 inches Subsea Pipeline
Major Process Facilities at CEP 1.0 TEG Gas Dehydration
TEG Contactor TEG Dehydration for natural gas TEG Regenerator
Natural Gas In
Natural Gas Out TEG In
TEG Solution out
Vapor
Major Process Facilities at CEP 2.0 EG Condensate Dehydration
EG Condensate Dehydration EG Regenerator
Natural Gas with Condensate In
Natural Gas Out
EG In
EG Solution out
Vapor
Condensate Separator
Major Process Facilities at CEP 3.0 Subsea Pipeline
Dehyed Gas and condensate FeedFrom CEP to Subsea Pipeline
261 Km- 30 –Inches Subsea Pipeline
To Gas Plant
PFD of CEP and Subsea Pipeline
Major Process Units at Gas Plant 1.0 Condensate Stabilization
Condensate Stabilization Condensate Stabilizer
Natural Gas with condensate In
Natural Gas Out
Condensate to
Vapor
Condensate Separator
Propane Cooler
Condensate Out
Major Process Units at Gas Plant 2.0 Propane Refrigeration
Propane inlet Scrubber
Propane Vapor
Propane Surge Tank
Propane Compressor
Propane Cooler
Propane Liquid
PFD - Condensate Stablization & Propane Refrigeraion
Major Process Units at Gas Plant 3.0 MDEA Gas Treating
Amine Contactor MDEA Amine Sweetening Amine Regenerator
Natural Gas In
Natural Gas Out Lean Amine In
Rich Amine out
Sour Gas
PFD- Amine Treating unit
Major Process Units at Gas Plant 4.0 Mole Sieve Dehydration
Mole Sieve TowerWet Natural Gas In
Dry Natural Gas Out Regen. Hot Gas in
Regen. Wet Gas in
Regen. Gas Compressor
Regen. Gas HeaterHot Oil
Major Process Units at Gas Plant 5.0 Refrigeration- Cold Box and Expander
Cold Box
Natural Gas in
LTSExpander-Compressor
Contacting Column
Compressor After coolerFeed to Deethanizer
Dry Gas to Sale Gas Compressor
Major Process Units at Gas Plant 6.0 Refrigeration- Cold Box and Deethanizer
Cold Box
Deethanizer
DeethanizerReflux Drum
Contacting Column Bottom to
Depropannizer
LTS bottom from Cold box
Major Process Units at Gas Plant 7.0 Fractionation - Deep Cuts
De-propanizer De-Butanizer
Mixed condensate
Propane
Butane
Condensate H.C.
PFD-Refrigeration & Fractionation
Major Process Units at Gas Plant 8.0 Sale Gas Compressor
Natural Gas in
Sale Gas Compressor
Sale Gas
PFD-Sale Gas Compression
Process Study Results:1.0 Major Sale Gas Flow Rate & Shrinkage Factor
2.0 Major Liquid Production Rates
3.0 Subsea Pipeline Operating conditions- Hydro-formation
4.0 Subsea Pipeline Operating conditions- Slug Flow Conditions
5.0 Gas Plant Operating conditions
1.0 Only One Train Capacity is adequate to process natural gas flow rates for the six years.
2.0 The major equipment will be running within design capacity, no overload
circumstances will take place in the typical six years.