Topsides Oil Production

Topsides Oil Production

A typical process consists of two-stage separation of oil from water. The first stage separation occurs in the HP Separator, where the majority of the water is separated from the oil and gives off gas, which passes on to the HP Scrubber (and then onto the HP Compressor.).

Oil from the HP Separator then passes onto the MP Separator where water is again separated and giving off more gas. This gas is passed on to the MP Scrubber (and on to the MP Compressor.).

Natural gas composition rich in methane, usually between 76 and 90 mole %, the remaining are the concentrations of hydrocarbons C4, C3 and C2.
Produced water passes to hydrocyclonic separation, where entrained or emulsified oil is removed, and then passes on to the de-gassing drum. From there it is re-injected back into the wells. Oil recovered from the hydrocyclones is fed back into the process at an appropriate point.

The process usually runs floating on two key pressure controls:
• MP Scrubber pressure control (MP Compressor suction)
• HP Compressor discharge pressure

Topsides Facilities Flow Diagram

Booster compressors and Injection compressor

Booster compressors

Gas transmission through pipelines results in pressure drop because of friction losses. Booster compressors are used to restore the pressure drop from these losses. Selection of these compressors involves evaluating the economic trade-off of distance between pipeline boosting stations and life-cycle cost of each compressor station. Booster compressors also are used in fields that are experiencing pressure decline. Most centrifugal pipeline booster compressors are gas turbine driven, although the use of variable-speed motor drives is becoming more prevalent. Low-speed integral gas engine reciprocating compressors also are used for gas transmission applications. Booster compressors typically are designed for high throughput rates and low compression ratio. Many booster applications can be configured in a single-stage centrifugal compressor.


Injection compressor

The injection of natural gas is employed to increase or to maintain oil production. Injection compressor is required to deliver gas at discharge pressures in excess of 10,000 psi. Injection compressor also are used for underground storage of natural gas. Compressors, applied to these services, have large compression ratios, high power requirements, and low volume flow rates.




Upstream Applications for Process Compressors

Gas Gathering (Inlet Boosting, Flash Gas Compression) for Associated Gas.

Application where associated gas from the oil production is compressed. At the wellhead, a mixture of hydrocarbons is present, and the goal is to separate the crude oil from its more volatile constituents, mostly natural gas. Typically, gas is separated from crude oil by flashing it at several pressure levels, leading to gas streams at a number of pressure levels, and different gas compositions (typically, the lower the pressure of the gas stream, the heavier is the gas). This gas is recompressed to about 70 to 100 bar (1000 to 1500 psi), and either used for gas lift, gas injection, or as sales gas.

In oilfield facilities, there are a number of conditions that often require the use of compressors. The most common use is the recompression of flashed gas for sale to a gas pipeline. The gas may have been at a low pressure for one of the following reasons:

• The wells may require a low flowing pressure in order to produce economic quantities, or
• Multiple stage separation may be necessary for proper fluid stabilization or other process requirements.

The gas may also need compression for reinjection into the formation, either as an interim measure awaiting a gas market or to maintain reservoir pressure.

Hydrocarbon Processing and Export

Separation

Hydrocarbon flow from the producing wells will be received at either the High pressure (HP) or Low Pressure (LP) production manifolds on the DUO platform and transferred to the two platform separation trains for separation into oil. gas and water phases. Each separation train will include a two-phase (gas from liquids) HP separator in series with a three-phase LP separator and coalescer. Wells on test will run via an additional test manifold and separator.


Separator Design Operating Specifications

Pressure (barg) Temperature (°C)
HP Separator 29 barg 40 to 55
LP Separator 12 barg 40 to 58


The separation trains will be designed to process up to:

• 316 Mbpd of oil;
• 350 MMscfd of high-pressure gas;
• 225 MMscfd low-pressure gas; and
• 131 Mbpd of produced water.


The majority of the gas present in the produced fluids will "flash off' in the HP Separator. This gas will be routed to the gas compression and dehydration system for further processing.

The liquid hydrocarbon phase from the HP separator will be routed to the LP separator for further separation into oil and water phases. Produced oil from the LP separator will fiow into the oil booster pumps. across the bridge and into the coalescer located on the PCWU platform. Thereafter it will pass to the main oil line (MOL) pumps. From here, it will be exported to the onshore terminal via the two 30" export oil pipelines. Produced water will be routed to the produced water treatment system and then to the water injection system.


Gas Processing

Gas removed from the HP separator will be passed to Gas treatment prior to export onshore via 28" gas line. Treatment will involve gas cooling and dehydration to remove water. Gas removed from the fiuids in the LP separator will be cooled and compressed via fiash gas compression before in contact with the HP gas upstream of the dehydration column (tri-ethelyne glycol (TEG) contactor). Final dehydration will involve use of glycol to remove any residual moisture to prevent hydrate formation and corrosion within the gas export pipeline. Used glycol will be recovered, treated in a glycol regeneration package and recycled. Water vapour generated in the package will be condensed and routed to the closed drains drum. Following final dehydration, the combined gas streams will be compressed to export pressure by 2 x 175 MMscfd electric driven compressors.

Unlike other topsides facilities, associated gas from Phase 3 will not be re-injected into the reservoir for disposal or pressure support purposes. A portion of the treated associated gas will however, be taken off and used as fuel gas on the platforms and for gas lift in producing wells.


Fuel Gas

Major Topsides Fuel Gas Users and Design Usage Rates

Platform User Design Rate (Sm3/hr) 1&2
Purge gas to HP and LP Hare headers: 300
Power generators (1 unit): 7,400 (15°C) and 6,812 (35°C)
Flare pilot light: 16
Glycol regenerator: 36
Water injection pump gas turbines (3 units): 21,600 (15°C) and 19,050 (35°C)
Power generators (4 units): 22,200
1 Standard cubic meters per hour.
2 Gas turbine design rates for power generation and water injection provided for both iso conditions (28MW power @ 15°C) and maximum ambient design (23MW power @ 35°C).


Fuel gas will be diverted from the HP gas process train downstream of the main export compressor. It will be passed on to the fuel gas system on Topsides where liquid condensate will be removed in the fuel gas knock out (KO) drum and returned to the LP separator train for processing. Gas will then be heated and filtered prior to use.

Under normal operations, the base fuel gas load will be approximately 50,000 Sm3/hr (46 MMscfd) based on four gas turbine power generators and three turbine driven water injection pumps operating at full capacity plus nominal usage by other fuel gas users. Maximum design capacity will allow for temporary operation of eight gas turbines plus auxiliary fuel gas users and the fuel gas KO drum will be able to provide sufficient gas inventory for automatic changeover of the gas turbine generators to diesel fuel in the event of loss of fuel gas.

Facilities will be provided to enable the import of gas onto the platform fuel gas system directly from the gas export line if required.


Gas Lift

Gas lift increases production flow-rate in low-pressure production wells and all production wells will be fitted with gas lift completion equipment. Gas lift will be required after the third year of production although it may be required for some wells from start up.

Gas for gas lift service, will be diverted from the HP stream downstream of the main export compressors. Maximum well injection rates will not exceed 6 MMscfd per well and average injection rates are expected to be 4 MMscfd per well.




Separation

The well-stream may consist of crude oil, gas, condensates, water and various contaminants. The purpose of the separators is to split the flow into desirable fractions.


Test separators and well test

Test separators are used to separate the well flow from one or more wells for analysis and detailed flow measurement. In this way, the behavior of each well under different pressure flow conditions can be defined. This normally takes place when the well is taken into production and later at regular intervals, typically 1-2 months and will measure the total and component flow rates under different production conditions. Undesirable consequences such as slugging or sand can also be determined. The separated components are analyzed in the laboratory to determine hydrocarbon composition of the gas oil and condensate.

Test separators can also be used to produce fuel gas for power generation when the main process is not running. Alternatively, a three phase flow meter could be used to save weight.


Production separators

The first stage separator. The production choke reduces well pressure to the HP manifold and first stage separator to about 3-5 MPa (30-50 times atmospheric pressure). Inlet temperature is often in the range of 100-150 degrees C. On the example platform, the well stream is colder due to subsea wells and risers.

The pressure is often reduced in several stages, in this instance three stages are used to allow the controlled separation of volatile components. The idea is to achieve maximum liquid recovery and stabilized oil and gas and to separate water. A large pressure reduction in a single separator will cause flash vaporization leading to instability and safety hazards.

The retention period is typically 5 minutes, allowing the gas to bubble out, water to settle at the bottom and oil to be taken out in the middle. In this platform the water cut (percentage water in the well flow) is almost 40% which is quite high. In the first stage separator, the water content is typically reduced to less than 5%.
At the crude entrance, there is a baffle slug catcher that will reduce the effect of slugs (large gas bubbles or liquid plugs). However some turbulence is desirable as this will release gas bubbles faster than a laminar flow.

At the end, there are barriers up to a certain level to keep back the separated oil and water. The main control loops are the oil level control loop controlling the oil flow out of the separator on the right, and the gas pressure loop at the top. These loops are operated by the Control System. An important function is also to prevent gas blow-by which happens when a low oil level causes gas to exit via the oil output causing high pressure downstream. There are generally many more instruments and control devices mounted on the separator.

The liquid outlets from the separator will be equipped with vortex breakers to reduce disturbance on the liquid table inside. This is basically a flange trap to break any vortex formation and ensure that only separated liquid is tapped off and not mixed with oil or water drawn in though these vortices. Similarly the gas outlets are equipped with demisters, essential filters that will remove liquid droplets in the gas.

Emergency Valves (EV) are sectioning valves that will separate the process components and blow-down valves, this will allows excess hydrocarbons to be burned off in the flare. These valves are operated if critical operating conditions are detected or on manual command, by a dedicated Emergency Shutdown System. This might involve partial shutdown and shutdown sequences since the flare might not be able to handle a full blow-down of all process sections simultaneously.

A 45,000 bpd design production with gas and 40% water cut will give about 10 cubic meters from the wellheads per minute. There also needs to be enough capacity to handle normal slugging from wells and risers. This means the separator has to be about 100 cubic meters, e.g. a cylinder 3 meters in diameter and 14 meters in length at the rated operating pressure. This means a very heavy piece of equipment, typically around 50 tons for this size, which limits the practical number of stages. Other types of separators such as vertical separators or cyclones can be used to save weight, space or improve separation.

There also has to be a certain minimum pressure difference between each stage to allow satisfactory performance in the pressure and level control loops.


Second stage separator

The second stage separator is quite similar to the first stage HP separator. In addition to output from the first stage, it will also receive production from wells connected to the Low Pressure manifold. The pressure is now around 1 MPa (10 atmospheres) and temperature below 100 degrees C. The water content will be reduced to below 2%.

An oil heater could be located between the first and second stage separator to reheat the oil/water/gas mixture. This will make it easier to separate out water when initial water cut is high and temperature is low. The heat exchanger is normally a tube/shell type where oil passes though tubes in a heating medium placed inside an outer shell.


Third stage separator

The final separator here is a two-phase separator, also called a flash drum. The pressure is now reduced to atmospheric pressure of around 100 kPa, so that the last heavy gas components will boil out. In some processes where the initial temperature is low, it might be necessary to heat the liquid (in a heat exchanger) again before the flash drum to achieve good separation of the heavy components. There are level and pressure control loops.

As an alternative, when the production is mainly gas, and remaining liquid droplets have to be separated out, the two-phase separator can be a Knock-Out Drum (K.O. Drum).



Glycol Dehydration Package

Description of gas dehydration package given below is typical. Exact configuration of glycol dehydration package shall be finalised by glycol dehydration package vendor.

Compressed gas from the HP Compressor After-cooler is fed to a TEG (Tri-Ethylene Glycol) based dehydration unit (1 x 100% capacity). The gas dehydration column (or TEG contactor tower) has its integral Inlet Scrubber for separation of any condensed liquid at HP Compressor After-cooler outlet. Collected liquid is routed to HP Compressor Suction Drum. The inlet scrubber outlet gas is in direct counter current contact, in a dehydration column, with lean TEG from TEG regeneration section. The dry gas off the top of the glycol dehydration column flows to the gas export pipeline for transmission to the gas gathering manifold on a Collector Riser Platform. In order to provide steady operating pressure in the dehydration column, a back-pressure control valve is provided at the column outlet. Further, for monitoring dew point of dehydrated gas, an online dew point analyser is provided on dehydration column outlet gas line.

The rich TEG from the bottom of the contactor tower is continuously regenerated in the regeneration section. Rich glycol from dehydration column is first heated, by exchanging heat with hot vapours in the top of the glycol still column (also called as regenerator column) followed by heat exchange with hot lean glycol from lean-rich glycol exchanger, before entering glycol flash drum in order to allow maximum dissolved gases to be flashed off. A HC skimming facility is provided in the glycol flash drum. This vessel is fuel-gas blanketed to maintain its pressure typically at ~ 4 barg. Two cartridge type filters (2 x 100% capacity) are provided to remove solids and other impurities from glycol solution. Additionally, a charcoal filter is provided downstream of cartridge filters. Rich TEG from filters is further heated by heat exchanger with lean TEG from reboiler and then routed to still column.

A reboiler with electrical heaters and integrated still column. Dry, sour stripping gas is provided to regenerate glycol solution to the desired strength (~ 99.1 wt% concentration), before it is returned to the top of the contactor tower. TEG regenerator section design is based on use of stripping column. However, requirement of stripping gas to meet water dew point specification of dehydrated gas (7°C at dehydration column top operating pressure) shall be confirmed by glycol package vendor. Fuel gas for regenerator reboiler and stripping gas, if necessary, is tapped from dehydration column outlet similar to fuel gas for gas turbine drive for compressors.

Still column overhead vapours are routed to flare system after cooling in overhead condenser system. For routing overhead gas to flare system, ejector is provided considering higher flare header back-pressure. Condensed liquid is routed to closed drain system by gravity flow. Regenerated glycol solution is then routed to gas dehydration column after cooling in lean/rich glycol exchangers and gas glycol cooler.

Chemical injection system for preventing foaming, solution pH control and corrosion inhibition is provided. Glycol make-up facility is also provided considering continuous loss of glycol with the dry gas and still column overhead vapours.



Gas Dehydration Package

PROCESS DESCRIPTION
The Gas Dehydration Package is designed to dehydrate natural gas using Triethylene Glycol (TEG) as Vendor proprietary process design technique and procedures.
Specification for Dry Gas Water Content (outlet): 4 lb/MMSCFD


1. Gas Dehydration Section (Off-skid)

Gas dehydration section consists of following equipment.
Inlet Scrubber
Glycol Contactor
Gas/Glycol Exchanger

Wet gas enters the Inlet Scrubber that separates water and HC condensed associated condensed liquids from gas. Here any liquid entrainments are collected mechanically, and then liquid free gas goes to Contactor. The feed gas enters the lower section of Glycol Contactor and flows upward through structural packing contacting with lean(dry) glycol coming from top of Glycol Contactor.

The contact on the structural packing allows the glycol liquid to absorb the water vapor of the gas stream. Dehydrated gas exits from the top of the Glycol Contactor, to next gas exporting section through Gas/Glycol Exchanger.

The rich (wet) glycol liquid, having absorbed the water from Natural Gas, is drawn from bottom of the Glycol Contactor by the automatic level controller. Lighter hydrocarbon condensed in the tower will be side cut manually from the overflow weir in the bottom section.


2. Glycol Regeneration Skid

The glycol regeneration section consists of following major equipment.
TEG Still Column
TEG Surge Drum
TEG Flash Drum
TEG Reboiler with Stripping Column
TEG Reflux Condenser
Hot and Cold Lean/Rich TEG Exchangers
Rich TEG Cartridge Filter
TEG Carbon filter
Glycol Circulation Pumps
TEG Make-up Tank

The rich TEG from the Contactor passes through the Glycol Reflux condenser on the Rich Glycol Stripper as coolant to provide reflux water. And it is damped through Cold Lean/Rich Glycol Exchanger to the Glycol Flash Drum which separates dissolved gases. Also, it separates insoluble hydrocarbon liquid from the glycol stream here.

The rich glycol flow from the Glycol Flash Drum is continuously and is controlled by level controller. Rich TEG Filters and Carbon Filter remove contaminant materials in the rich glycol stream.

The glycol flows to the Hot Lean/Rich Glycol Exchanger for heat recovery and enters the Rich Glycol Stripper.

The Glycol Still Column concentrates glycol to required concentration at lower section and recovers glycol from removed water at top section to reduce glycol loss.

The concentrated glycol flows to the kettle type Glycol Reboiler where boiling is done by Electric Heater. The glycol is heated to 400°F bath temperature.

Hot glycol flows to the Glycol Surge Drum through the Glycol Stripping Column where recycled dry stripping gas will strip water vapor at the desired level 99.7wt% lean glycol.

Lean glycol flows to Glycol Pumps through Hot/Cold Lean/Rich Glycol Exchangers and enters the Glycol Contactor after cooling down by Gas/Glycol Exchanger.

The lean glycol stored in the nitrogen blanketed make-up storage tank is pumped to the Surge Drum for making up any loss of glycol.



Gas Dehydration Using Glycol

PROCESS DESCRIPTION

Dehydration of natural gas flow and glycol. Wet natural gas first flows through an inlet separator or scrubber to remove all liquid and solid impurities. Then the gas flows into and upward through Glycol Contactor where it is contacted countercurrently and dried by the glycol. Finally, the dried gas passes through a Gas/Glycol Exchanger, and then into the gas export line.

Reconcentrated or "lean" glycol is pumped by Glycol Circulation Pump to the inlet at top of the Contactor, in the Contactor it flows downward from tray to tray and absorbs water from the rising natural gas. The wet or "rich" glycol (high water content) leaves Glycol Contactor and flows through a heat exchanger coil located on top of Glycol Still Column on the Glycol Reboiler, where it is preheated by hot lean glycol. After the glycol-glycol heat exchanger the rich glycol enters the stripping column and flows down the packed bed section in the Glycol Still Column into the glycol reboiler vessel, where Electrical Heaters provide heat to the necessary high regeneration temperature. At the high temperature, the glycol loses its ability to hold water; the water is vaporized and leaves through the top of the Glycol Still Column.

The hot reconcentrated glycol flows out of the reboiler into Stripping Column, a small packed column between the reboiler and the surge drum and the gas is introduced at the base of this column. By contacting the hot glycol with natural gas, an additional small amount of water is “stripped” from the glycol into the gas, increasing the purity of the lean glycol. If a packed column is used as a contacting means between the glycol and the stripping gas, the stripping efficiency is considerably improved.

Lean glycol leaves Stripping Column at bottom and flows into a heat exchanger where its temperature is reduced by heat exchange with rich glycol. Finally, the lean glycol flows through the glycol/gas exchanger and enters Glycol Surge Drum and is pumped back into the top of the Contactor.

1. Heat exchange between the cool, rich glycol and the hot lean glycol is improved by using two or more shell and tube heat exchangers in series. The increased heat recovery reduces fuel consumption in the reboiler and protects the Glycol Circulation Pump from being overheated; it also allows the Glycol Flash Vessel and filter to operate at approximately 65.6°C (150°F).

2. Rich glycol is flashed to remove dissolved hydrocarbons. The gas released can be used for fuel and/or stripping gas.

3. The rich glycol is filtered before being heated in the Glycol Reboiler. This prevents impurities such as solids and heavy hydrocarbons from plugging the packed column and fouling the Glycol Reboiler Heater Bundle.







Glycol Contactor
Wet Gas flow in through the bottom of the Contactor. Contactor section is equipped with a mesh-type Mist Eliminator that serves as a drip catcher and liquid hydrocarbons to flow down Contactor. Then also equipped with Level Gauge and Level Control Valve. In the conditions of low-level low will enable Shut Off on Level Control Valve
to prevent gas bursts into Regeneration System.
A mesh-type Mist Eliminator is also placed in the top of the Contactor to minimize glycol carried upward along Dry Gas. Wet Gas flows from the bottom to the top and opposite to the flow of glycol that comes from the top down.
Rich glycol which is rich in water content of the Wet Gas exit through the bottom of the Contactor, and is controlled automatically by Level Controller, And then flows into the part Regeneration System.

Gas / Glycol Heat Exchanger
Lean temperature Glycol Contactor coming into very influential on the dew point of the Dry Gas and loses glycol. So that the temperature should be kept higher than the temperature Gas Inlet / Wet Gas so that no condensation at the exit of the Contactor. Condensing gas at the top would cause frothing at the Contactor.
Therefore the inlet temperature should Glycol Lean 15°F above ambient Gas Inlet. Heat Exchanger used is of TEMA type.

Flash Tank
Glycol Flash Tank is located below the reflux condensor and serves to separate and eliminate flash gas and liquid hydrocarbons from Rich Glycol. If these contaminants are not removed then it will affect the performance of the glycol reboiler and efficiency of Regeneration System. Which can cause froth / foam in the system. A horizontal three-phase separator with internal weir plate is provided. In addition, Flash Tank designed to have sufficient time to process the release / eliminate the contaminant content of which will be above the Rich Glycol. Flash gas will exit through the Vent Line, and Rich Glycol will flow to Still Column.

Glycol Lean / Rich Glycol Heat Exchanger
Glycol / Glycol Heat Exchangers Shell & Plate is manifold HE. Serves as a coolant of Hot Lean Glycol to below 185°F so that the pump Glycol is not damaged due to the pump design temperature is 200°F.
Heat exchange occurs when Rich Glycol flowing in the Shell has a lower temperature than the Lean Plate Glycol flowing in. So Rich Glycol be hot and it will make the efficiency will be higher reboiler Glycol (requires a low duty).

Glycol Sock Filters
Has 2 x 100% with 3 filter elements mounted inside. The function of the filter is to remove solid contaminants in the glycol while bringing gas from the feed, upstream line and crusts vessel.
This filter is designed to be able to eliminate solid particles with a size of 10 microns and an efficiency of 90%. The maximum limit allowable pressure drop amounted to 14.7 psi.

Glycol Charcoal Filters
Glycol Charcoal Filters Filters installed after Glycol Sock. Dirt chemical, hydrocarbon liquid and degraded TEG will be absorbed by the third filter installed in the vessel.
Glycol Charcoal Filters will be off if the maximum pressure drop (14.7 psi). Thus the filter element must be replaced with new ones.

Still Column with Glycol Reflux Condenser
Still Glycol Column mounted directly on top Glycol reboiler to allow glycol get quite hot. Rich Glycol heat is introduced into the central part Glycol Still Column.
At the bottom of packaged parts, heating and rich glycol fractional distillation occurs. Packed section above serves to minimize the amount of glycol loss left the air with water vapor.
Glycol reflux condenser is an integral part of the glycol still column. Rich glycol from the contactor passing reflux condenser to get the heat from the water vapor in the still column. This reflux ensures that all the glycol in the water vapor condenses and returns back to the column packing glycol still giving fractionation process. Once the Bypass valve of the condenser is set to control manually the temperature difference between inlet and outlet by TDI (Temperature Differential Instrument) showed about 17 °F, so as to maintain the required reflux at the top of the column still glycol.

Glycol reboiler with Stripping Column

Glycol reboiler serves to purify the glycol concentration vaporize and remove water that had previously been absorbed in the Contactor with direct heating method. It is designed to prevent or minimize the thermal degradation of glycol due to hot spots on the heating surface.

Glycol reboiler operates at a pressure of 3.0 psig to resist back pressure from the flare header operating at normal pressure 2.5 psig. Operating temperature Glycol reboiler set at 400°F, where 98.8% wt was achieved without stripping gas. To achieve glycol with a high concentration (99.5% wt) there must be additional Stripping Column installed in the vessel. Stripping excessive gas can cause high loses in Glycol through evaporation so that there should be a control on the flow rate is.

Glycol Surge Tank
Designed to keep the volume of glycol to adequately accommodate the volume changes due to thermal expansion when the system is heated.

Booster Pumps (Optional)
Booster pump provided only to provide sufficient NPSH to glycol circulation pump which in this design is not always operated. Provided for the purpose of stand-by.

Glycol Circulation Pumps
Two electric motors supplied pumps for pumping of Lean Glycol Glycol / Glycol HE Gas / Glycol HE. This pump is designed to have around 178 psi diff. pressure and power of 7.5 kW (10.0 HP) at 1500 RPM. One is a stand-by system.




Dehydration Process
General
A natural gas stream can be dehydrated by contacting the gas with glycol. This process is normally carried out at an elevated pressure in a vessel called a contactor or absorber. After absorbing the water, the glycol is reconcentrated by boiling off the water at atmospheric pressure in a regenerator. A pump is used to recirculate the glycol to the contactor.

Inlet Scrubber
An inlet scrubber is required, either integral with the contactor or as a separate vessel upstream, to remove free liquids from the gas stream going to the contactor. The mist extractor in this vessel removes larger droplets entrained in the gas.

Contactor
The contactor vessels may be categorized as to the manner in which the absorption process is accomplished. One type uses trays equipped with bubble caps, valves, other devices, to maximize gas-to-glycol contact. The action of the gas flowing upward through the glycol layer on each tray creates a froth above the tray, where most of the absorption takes place. The other type of contactor is referred to as a packed tower. It is filled with packing, which has a large surface area per unit volume. Glycol flowing downward wets the entire packing surface. Absorption takes place as the gas flows upward through the packing, contacting the wetted surface. In either type of vessel, a mist extractor removed entrained glycol droplets from the dehydrated gas stream before it leaves the top of the contactor. On larger units, an optional residue gas scrubber may be justified. Rich (wet) glycol is directed from the bottom of the contactor to the regeneration system.

Gas/Glycol Heat Exchanger
Absorption is improved with lower temperature glycol. A gas/glycol heat exchanger is required, which uses dehydrated gas to cool the lean (dry) glycol before it enters the top of the contactor.

Regeneration System
The regeneration system consists of several pieces of equipment. If glycol-gas powered pumps are installed, energy from the high-pressure, rich glycol, along with a small amount of gas, is used to pump the lean glycol.

If an optional reflux coil in the still column is provided, the rich glycol flows through it before entering the glycol/glycol heat exchanger. The glycol/glycol heat exchanger serves two purposes:
1.To cool the lean glycol to a temperature as recommended by the pump manufacturer.
2.To conserve energy by reducing the heat duty in the reboiler.

Gas-Condensate-Glycol Separator
A frequently used option in regeneration systems is a gas-condensate-glycol separator, which should be included when the inlet gas contains condensate. It may be located upstream or downstream of the glycol/glycol heat exchanger and usually operates at a pressure of 25-75 PSIG. It removes condensate from the glycol prior to the reboiler, which minimizes coking and foaming problems. The separator also captures flash gas that is liberated from the glycol and exhaust gas from the glycol-gas powered pumps so that the gas may be used as fuel. Glycol is regulated from the separator to the reboiler by means of a level controller and dump valve. Condensate removal may be controlled automatically or manually.

Reboiler
Rich glycol enters the reboiler through the still column. It is then heated to 350-400°F, which causes the water that was absorbed in the contactor to vaporize. The reboiler is usually heated by combustion of natural gas, but may utilize other fuels, steam, hot oil or other heat sources. The regenerated lean glycol gravity feeds from the reboiler, through the glycol/glycol heat exchanger and into the pump suction for recirculation back to the contactor. Either electric, gas-powered, or glycol-gas powered pumps may be used.

Still Column
Water and glycol vapours from the reboiler enter the bottom of the still column, which is mounted on top of the reboiler. The bottom section contains packing, while the top section of the still column may contain a reflux coil or external fins. Reboiler vapours are cooled and partially condensed to provide reflux, which improves the separation between glycol and water. The remaining water vapour leaves the top of the still column and vents into the atmosphere.

Filters and Strainers
Regeneration systems contain various types of filters and strainers. A particle filter or fine mesh strainer is required to protect the pump. To reduce foaming, an activated carbon filter may be installed to remove heavy hydrocarbons from the glycol. There is no standard arrangement for these items in the system.


Glycol Gas Dehydration
Water saturated natural gas passes through an Inlet Scrubber to remove contaminants before entering Glycol Contactor, to ensure optimal performance and longevity of the glycol. The scrubbed wet gas enters the contactor then flow up through a chimney tray into the absorption section of the Contactor, which typically contains between four and ten bubble-cap trays. Lean glycol, normally containing 0.5 to 2% water, is fed to the top of the Contactor and absorbs water from the gas while flowing downward through the column. The dried gas leaves the top of the contactor and is used to cool the glycol feed. As indicated on the flow diagram, it may then pass through a scrubber which remove any entrained glycol droplet before the product gas enters the pipeline.

Rich glycol flowing out of the bottom of the contactor typically contain 3 to 7% water and glycol must be lean (reconcentrated) before it can be reused for water absorption. The rich glycol is often used to provide cooling and condense water vapor at Glycol Reflux Condenser on top of Glycol Reboiler. This raises the temperature of the rich glycol, which then may be further heated by heat exchange with hot lean glycol. It then enter a reduced pressure flash Vessel where dissolved hydrocarbon gases are released. The released gases are recovered and used for fuel or other purposes.

After flashing, the rich glycol passes through a filtration system and a second glycol/glycol heat exchanger where it is further heated, and finally enters the reconcentrator column above a short packed or tray section. Efficient recovery of heat from outlet of reboiler is necessary to minimize fuel consumption in the reboiler.

Because of the extreme difference in the boiling point of glycol and water, a very sharp separation can be achieved with a relatively short column. Water reflux must be provided at the top of the column to effect rectification of the vapors and minimize glycol losses in the overhead vapor stream. This is normally provided by condensing a portion of the overhead vapor. The amount of reflux is held at the minimum consistent with good plant operation because it directly affects the quantity of heat required in the reboiler. Typically, a condenser heat duty of about 25% of the reboiler dUly will provide sufficient reflux to limit glycol losses to less than 2 lb glycol per MMScf of feed gas (GPSA, 1987). In the flow diagram the extent of vapor condensation is controlled by a simple bypass valve in the rich solution line. More effective control can be attained by using a three-way valve in the solution line to apportion solution between the reflux coil and the bypass line in response to a temperature sensor located at the top of the still column (Bucklin, 1993).

Heat for the distillation is provided by a direct fired reboiler. Hot Lean glycol leaves the reboiler and flows to a surge Vessel (which often contains cooling coils) and is pumped through the glycol/glycol heat exchangers and back to the Contactor.

The degree of dehydration that can be attained with a glycol solution is primarily dependent on the extent to which water is removed from the solution in the reconcentrator. The operation of atmospheric pressure distillation unit for water removal is limited by the maximum temperature that can be tolerated without excessive decomposition of the glycol (about 400°F for TEG). Concentration of TEG to 98.5 to 99.0% is attainable in a simple atmospheric pressure still. When ignificantly higher concentration are needed to meet stringent gas dehydration requirements, the use of an enhanced stripping technique is necessary.

Stripping Gas Column operates on the hot lean glycol flowing from the reboiler to the Surge Vessel. When this type of stripping is used, a small stream of dry natural gas is fed into the bottom of the stripping gas column to reduce the partial pressure of water vapor in the gas phase. The gas aids in removing water from the glycol and finally leave the primary, stripping column with the vented water vapor.

A simpler but less effective technique is to inject the inert gas directly into the glycol in the reboiler. According to Wieninger (1991), a concentration of 99.5% can be obtained by injecting stripping gas into the reboiler, and a concentration a high as 99.9% can be obtained with a separate stripping gas column between the reboiler and the Surge Vessel.





SCOPE OF SUPPLY
Vendor offers to deliver one dehydration system to be installed on Platform.
Vendor scope of supply includes the main following equipment:
· One glycol absorber column supplied as loose item
· One glycol cooler supplied as loose item.
· One glycol regeneration package supplied as a single skid

BASIS OF DESIGN
General
Glycol absorber is designed for the following operating conditions:
Temperature = 131 (°F)
Pressure = 865 (psig)
Mass flowrate = 1 271 000 (lb/hr)
Vol. Flowrate = 602 (MMSCFD)
Molecular Wt = 19.2
Density = 2,98 (lb/ft3)
Water content = 123,6 (lb/MMCSF)

Gas composition (%mol)
CO2
N2
Methane
Ethane
Propane
n-Butane
i-Butane
n-Pentane
i-Pentane
Pseudo C6
Pseudo C7
Pseudo C8
H2O
H2S
Other

Main process data
· Inlet water content : Saturated
· Outlet water content : 4 lb/MMSCF
· Water removed : 4104 lb/h
· Lean glycol flowrate : 92,483 lb/h
· Lean glycol concentration: 99.95%wt

PERFORMANCES
For dehydration system operating under steady conditions as specified.
of this document, the following performances are guaranteed by Vendor.
· Dry gas leaving glycol absorber will have a water content of 4 lb/MMSCF
corresponding to a water dew point of 15.8 °F@879.7 Psia.
· Glycol regeneration is designed to handle the lean glycol capacity of 92 483 lb /h at a
concentration of 99.5%wt.
· Pressure drop across glycol absorber will not exceed 50 kpa.

UTILITIES CONSUMPTIONS
Glycol regeneration package designed and supplied by Vendor will have the main following utilities consumption.
· Fuel gas : 1.3 MMSCFD
· Electricity : 180 kW
· Air instrument : 15 Nm3/h

DESCRIPTION OF SUPPLY
Glycol absorber
Glycol absorber supplied by Vendor has the main following characteristics:
· Type : Structured packing
· Internal diameter : 3 500 mm
· Height : 11 000 mm
· Mechanical design and construction code : ASME VIII Div 2
· Mechanical design pressure : 1 100 psig
· Mechanical design temperature : -50/185°F
· Estimated empty weight :
· Estimated thickness :
· Material : Carbon steel + 3mm inconel 625 weld overlay.
The absorber is equipped with the following internals:
· One inlet device
· One bottom demister
· One structured packing bed with associated grids
· One chimney tray
· One top demister
· One glycol distributor
· One vortex breaker.
All those internals are made of stainless steel and are removable through man way except the chimney tray.
Delivery:
The absorber is delivered as loose item without any piping, platform, accessories, ladders, instruments and valves.
Structured packing will be delivered in wooden crates and shall be installed on site by other when absorber will be in vertical position.

LEAN GLYCOL COOLER
One lean glycol cooler is supplied by Vendor, it has the main following characteristics:
· Type : Induced draft air cooler
· Duty : 4 470 000 Btu/h
· Size : 3.1m x 9m
· Tubes : Material : Carbon steel
Size : 1”
Length : 25’
· Electricity : 2 motors
10 kw
Eexed
Preliminary empty weight is 15 tons.

GLYCOL REGENERATION PACKAGE

One glycol regeneration package is supplied.
It is designed to regenerate lean glycol flowrate associated to glycol absorber.
Glycol regeneration package is supplied as a complete unit mounted on skid, including the main following equipment:
· One glycol reboiler
· One still column with integral reflux condenser
· One stripping column
· One cold lean /rich glycol exchanger
· One hot lean/rich glycol exchanger
· Two glycol particulate filters
· One glycol charcoal filter
· One flash drum
· One glycol surge Vessel
· Two glycol circulation pumps
· Associated piping, instruments and valves.

Size of main equipment
Each equipment will have the main following characteristics summarized below:

Glycol Reboiler
Multi tube, fire heater type
Installed duty : 3500 kW
2.7 m x 9 m
Carbon steel

Glycol Still column
Packed type
1.05 m x 6 m
It includes a BEM shell & tube heat
exchanger for reflux
Duty is 360 kW
Stainless steel

Cold lean/rich Exchanger
Type: Plate
Duty: 390 kW
Carbon steel/titanium

Hot lean/rich exchanger
Type: Plate
Duty: 2450 kW
Carbon steel / titanium

Glycol particulate Filters
Type: cartridge
Quantity: 2
Capacity : 100% glycol flowrate
Filtration: 10 microns
0.71 x 1.75 m
Carbon steel

Glycol Charcoal filter
Quantity : 1
Capacity : 10% rich glycol flowrate
0.711 m x 2 m
Carbon steel

Glycol Flash drum
Type: three phase, horizontal
Retention time: 30 minutes
2.1 m x 7.5 m
Carbon steel

Glycol Stripping column
Type : packed
0.95 m x 3.8 m
Carbon steel

Glycol surge tank
1.8 m x 6 m
Carbon steel

Glycol circulation pumps
Quantity : 2
Type : reciprocating
Capacity: 47.5 m3/h
Power : 100 kW
Carbon steel

Assembly
All those equipment are mounted on a single skid.
· Sizes are : 15 000 mm (l) x 9 000 mm (w)
· Empty weight : 150 tons




Processing plants for the hydrocarbons produced

The high cost of offshore units means that treatment carried out on the platform must be kept to a minimum, reducing the corrosiveness of the hydrocarbons to allow their transport to gathering stations along the coast. Any further treatment required will be carried out here; on the platform we only carry out treatment involving the separation, dehydration, and heating or cooling of reservoir fluids.

Separation allows us to separate gases from liquids (crude oil, condensates and water). During this process, any sand dragged along with the fluids, which may cause erosion can also be removed.

Dehydration allows us to remove the water contained in crude oil or natural gas, in order to avoid the formation of hydrates during transport through the pipeline; these solidify when the fluid cools and risk causing obstructions. The most frequently used method involves bringing the hydrocarbons into contact with a pure glycol solution. Facilities for the separation of water from crude oil also remove other impurities present and collect the petroleum vapours contained within it separately.

The fluids produced are heated and cooled in accordance with varying processing requirements and the properties of the products to be treated.

At times, after a few years of production, we may need to inject water or gas into the reservoir to maintain reservoir pressure at an acceptable level. In these cases, the platform also hosts facilities for re-injection through purpose-drilled wells or depleted production wells.

Utility systems for primary processing

In order for the hydrocarbon treatment plants to function, and for the platform to operate with the requisite safety and reliability, it must also include a series of utility systems. These facilities are:

• Power generated unit to power all the electrical equipment on the platform. This usually consists ofseveral turbines running on both gas and diesel oil (normally natural gas produced from the reservoir;gas oil during start-up or if production is halted).
• Treatment plant for the gas used to power the turbines.
• Plants for the injection of chemicals, under the form of corrosion inhibitors, into the export pipeline (e.g. methanol, usually injected every time the platform is started up).
• Glycol regeneration unit for the glycol used to dehydrate gas; as it exits the dehydration column, the regeneration unit separates the glycol from the water, and recovers it.
• Diesel oil distribution system: the diesel oil is stored in tanks and used to power turbines, emergency generators, fire pumps and other motors.
• Unit which supplies compressed air to all the field equipment and other utilities on the platform.
• Refrigeration units: the need to cool processes and support facilities is met by using refrigerating water which circulates in a closed loop, and is cooled in seawater exchangers.
• Seawater collection and distribution plant: seawater is pumped to the platform by submerged pumps installed inside tubular caissons at a depth of a few tens of metres. Seawater is used as a coolant in exchangers, to feed desalination and purification plants, and during drilling operations.
• Desalination and purification plant: this water is then distributed to worker accommodation, utilities, laboratories, the drilling rig and the emergency showers needed for instant decontamination of personnel.
• Plants to collect discharges from equipment and waste water.
• Treatment plant for the water separated from reservoir fluids during processing: this water is treated to recover the hydrocarbons remaining in it after the primary separation process; the recovered hydrocarbons are fed into the production system, whereas the water is discharged into the sea aftertreatment to limit the pollutants it contains as far as possible.
• Sewage treatment plant to treat sewage from worker accommodation and utilities.
• Nitrogen generation plant to power some specific utilities.
• Biocide liquid distribution plant, used to prevent organic growth inside the pipes of fire-fighting systems.


Safety and emergency systems

Safety systems significantly condition offshore units; those normally used on platforms are as follows:
• Emergency generator system: consisting of one ormore generators powered by diesel oil, which become operative if the primary generator systems fail.
• UPS (Uninterruptible Power Supply) system: consisting of a series of batteries to power vital platform systems which become operative if both the primary and emergency generators fail.
• Shut-down system: which shuts down production in case of accident.
• Detection system, which uses a series of sensors placed throughout the platform to detect the beginnings of a fire, smoke or gas leaks, and thus activate alarm and protection systems.
• Active fire-fighting systems: these use water,foam, carbon dioxide and inert gas, and protect the entire platform; the water is pumped directly from the sea, whereas the other substances are stored in tanks.
• Passive fire-fighting systems, consisting in the application of appropriate materials resistant to high temperatures on all those parts of structures and facilities at risk of prolonged exposure to fire in case of accident, and whose collapse could prejudice the safety of the entire platform. Additionally, the well and processing zone is generally isolated from other areas of the platform with explosion-proof walls.
• Personnel evacuation systems: generally life boats and life rafts, suitably distributed around the platform.
• Security and protection systems for workers: these are located at strategic points around the platform, and include life-jackets, gas masks, showers foruse in case of contact with dangerous substances,etc.
• Alarm systems: these consist of acoustic and visualdevices which are switched on automatically in case of emergency.
• Telecommunications systems: these allow workers on the platform to communicate internally and with the outside world to request help in case of emergency.


Oil and gas pumping or compression systems

Often, after treatment carried out on the platform, the pressure of the hydrocarbons produced is insufficient to propel them onshore through subsea pipelines, and we need to increase it. For gas especially, pressure is usually initially sufficient to avoid the installation of compressors to propel it onshore; however, over the years, pressure tends to decrease as a result of continued production, and it later becomes necessary to install compression systems.

The platform also hosts the devices (pigs) which are propelled through the entire pipeline by the fluid pressure, allowing it to be cleaned, and the conditions of the pipeline to be inspected. The pig is inserted through sidelines in the main pipeline (pig trap), with trap doors for the insertion or recovery of the pig.


Control system and control rooms

The production and processing plants, and supportand safety systems are constantly monitored by a data capture and processing system run from a control room which represents the heart of the platform. From the control room, operators can work on the entire platform, using control panels which show the functioning of the platform in a schematic way using graphic displays; these also allow operators to intervene remotely.

The functioning of the platform is monitored uninterruptedly 24 hours a day, usually by two groups of operators who work on different panels: one groupworks on the processing plants and utilities systems,whilst the other monitors the electrical generator and distribution systems.

The monitoring and data capture system constantly records operational data from all the appliances. Their working history can thus also be used to plan andrecord maintenance work on the platform.


Technical rooms and laboratories

Alongside the control room, platforms usually host other technical rooms: one or more electrical rooms, where the electrical distribution switchboard, batteries and transformers are installed; a room containing the refrigeration units for air-conditioning plants; a workshop for minor repairs or maintenance work, and laboratories to carry out chemical and physical analyses of production fluids.


Accommodation and living quarters for workers

Platforms are generally manned. Workers (up to 100-150 people on large platforms) are housed in aspecific area of the platform, which for safety reasons is as far as possible from wells and processing plants. Accommodation and common rooms are generally grouped together in a special module on several floors. Alongside the cabins for personnel, this also hosts other common areas such as: offices and meeting rooms, infirmary, radio and telecommunications room, kitchens, store room,laundry, canteen, recreation rooms, TV rooms, gym,etc.

The accommodation and common rooms, servedby an air-conditioning and ventilation unit, are slightly pressurized to prevent the entrance of any toxic gases, which may leak from facilities in case of accident.


Flares

A unit is needed to collect the discharges from thevarious processing plants (hydrocarbon and natural gas vapours), and dispose of these. The gas to be eliminated is sent to a burner placed at the far end of a metal framework, known as the flare; its length,depending on the maximum amount of gas which can be burned, may easily reach a hundred metres. The flare is oriented so as to be downwind of the prevailing winds.


Equipment for moving materials

Materials are moved onto the platform using cranes, placed so as to serve the entire upper deck surface of the topside. Access for the cranes to the lower decks is ensured by the presence of suitably positioned cantilevered loading bays.

The cranes, which can lift several tens of tonnes, are used to load and unload materials onto or from the transport vessels which supply the platform. Materials are moved around the platform on monorails serving all critical areas; less heavy materials can be moved using transport trolleys



Crude Separation

The well fluids are heated in the Production Heater to a suitable temperature for achieving the bulk oil and water separation as well as separating hydrocarbon gas from the liquids in the Production Separator.
Typically, on the Bluewater FPSOs, the operating conditions in the Production Separator are 10 barg and 60-80°C.

The Production Separator operates as a three-phase (oil, water and gas) separator. The separator is equipped with an inlet device, plate packs, a weir, vortex breakers and a demister in the gas outlet. If
sand is present in the well fluids, it will mainly collect in the Production Separator and therefore sand removal facilities are installed.

Produced water from the Production Separator flows under level control to the Produced Water System.
Hydrocarbon gas is cooled in the MP Gas Cooler and condensed liquids are separated from the hydrocarbon gas stream in the MP Gas KO Drum. The collected liquids flow to the Second Stage Separator. The MP gas is compressed in the MP gas compressor.

Oil from the Production Separator flows through the Interstage Heater to the Second Stage Separator.
The Interstage Heater heats the crude further to assure that the stabilization specification of the crude is met. The stabilization specification is noted as True Vapour Pressure (TVP) or Reid Vapour Pressure (RVP).
The Second Stage Separator operates similar as the Production Separator, i.e. a three-phase separator and is equipped with similar internals as the Production Separator.

The operating conditions of the Second Stage Separator are typically 80-90°C and 0.5-1.5 barg. The oil stream flowing into the Second Stage Separator contains up to 10 vol. % produced water. In the Second Stage Separator produced water is separated form the oil and the flashed off hydrocarbon gas, due to heating and pressure reduction, is separated from the liquids.

The hydrocarbon gas is cooled in the LP Gas Cooler and condensed liquids are separated from the hydrocarbon gas stream in the LP Gas KO Drum. The collected liquids are pumped to the Second Stage Separator using the LP Condensate Pumps.

The produced water separated in the Second Stage Separator is returned to the Production Separator with the Second Stage Produced Water Pumps.

The oil from the Second Stage Separator is pumped with the Produced Oil Pumps to the Desalter/Dehydrator. The desalting functionality could be combined with the dehydration functionality into one vessel. For other fields desalting is not required and only a Dehydrator is installed.

Both the Desalter and the Dehydrator are Electrostatic Coalescers. A voltage difference on plates enhances the separation between oil and water. The description below describes the combined desalting and dehydration functionality.

Deaerated seawater, seawater is less salty than produced water, is used for desalting. The seawater is mixed upstream of the Desalter and originates from the Water Injection System. A typical salt specification is 35 ptb (Pounds per Thousand Barrels). The incoming stream of the Desalter/Dehydrator contains about 10 vol % water in oil. The dehydration functionality reduces the water content to 0.5 vol.
% to achieve an oil specification of 0.5 % BS&W (Base, Sediment and Water). The Desalter/Dehydrator operates at 4-5 barg and 80-90°C.

The separated water in the Desalter/Dehydrator is returned to the Second Stage Separator.
The oil stream from the Desalter/Dehydrator is cooled in the Crude Cooler to 40-45°C and flows to the cargo tanks. The crude is cooled to minimize loss of oil due to flashing of the crude in the cargo tanks,
limit stresses in the hull due to high temperatures and prevent damage to the coating of the cargo tanks.
Furthermore without cooling the vapour pressure of the crude would be too high to assure problem free offloading.

The Test Sand Filter, Test Heater and Test Separator operate parallel of the Production Heater and Production Separator. The test train is used to test the characteristics of one well by treating the well
separately from the other wells. The oil from the Test Separator flows to the Interstage Heater and the hydrocarbon gas flows to the MP Gas Cooler. The produced water stream is treated in the Produced Water
System. Alternatives for a test train are the installation of a multi-phase flow meter or testing by difference.
All outlet streams of the Test Separator are measured and sampled to determine the well characteristics.
The Test Sand Filter will be used to detect if a well is producing sand. During the test the Test Sand Filter will be online and any produced sand will be collected. After the test the filter can be opened and inspected for sand and if necessary sand can be removed.


Produced Water
Produced water originates from the Test Separator and the Production Separator. All other sources of produced water such as the Second Stage Separator and the Desalter/Dehydrator are returned to the Production Separator and Second Stage Separator, respectively. The produced water from the Test Separator and Production Separator flows to the Test and Production Hydrocyclone, respectively.

Produced water to be treated still contains about 1000 ppmv oil. To separate the oil from the water the high pressure of the stream is used in a hydrocyclone to create a centrifugal force, separating the produced water stream in an oil lean and an oil rich stream.

Oil rich stream; reject stream, of both hydrocyclones returns to the Second Stage Separator whereas the oil lean stream flows to the Produced Water Degasser. The Produced Water Degasser ensures the hydrocarbon gas that is dissolved in the produced water flashes off and any residual oil in the produced water can be skimmed off. The Produced Water Degasser operates as a three-phase separator. In case the produced water specification is very stringent, less than 30 ppmv, the Produced Water Degasser can be equipped with a hydrocarbon gas sparger. The hydrocarbon gas bubbles that will rise through the produced water will improve the skimming of oil. The skimmed of oil is drained manually to the closed drains systems. The flashed off hydrocarbon gas is routed to the LP flare.

Produced water is pumped using the Produced Water Pumps through the Produced Water Cooler and is dumped overboard. In case the produced water is not meeting the overboard specification the produced water is routed to the slop tanks for further treatment. The produced water is cooled as legislation in some countries does not allow produced water to be dumped overboard hot (above 40°C), to prevent damage to coating of the slop tank and to limit stresses in the hull. A typical produced water specification is 40 ppmv of not dissolved oil in water.


Gas Compression and Treatment
The LP hydrocarbon gas from the LP Gas KO Drum is compressed in the LP Gas Compressor. The LP Gas Compressor typically an electrical driven two stage reciprocating compressor compresses the LP gas to
the MP gas operating pressure.

The LP gas is combined with the MP gas and is compressed further in the MP gas compressor and the HP gas compressor. The system as described below is a typical description of such a system. The ultimate solution chosen depends amongst others on the gas flow rate and the required discharge pressure.

The MP hydrocarbon gas from MP gas KO Drum and the LP gas compressor flows to an electrical driven two stage centrifugal MP gas compressor. The first stage compresses the gas from 9 barg to approximately 25 barg and the second stage compresses the gas to 65 barg.

The gas from the MP as KO Drum flows into the 1st Stage MP Suction Scrubber, the 1st Stage MP Gas Compressor and into the 1st Stage MP after Cooler. The anti-surge/recycle of the 1st Stage MP Gas Compressor is taken upstream of the 1st Stage MP After Cooler and therefore a dedicated 1st Stage MP Recycle Cooler is installed.

The compressed and cooled gas of the first stage flows into the 2nd Stage MP Suction Scrubber, the 2nd Stage MP Gas Compressor and is cooled in the 2nd Stage MP Discharge Cooler. The anti-surge and recycle
of the 2nd stage MP gas Compressor is taken upstream of the 2nd Stage MP Discharge cooler and flows back to the 1st Stage MP After Cooler.

The liquids that condensed in the 2nd Stage MP Discharge Cooler are separated from the gas in the 3HP Suction Scrubber. The gas flows to the Glycol Contactor. In the Glycol Contactor the gas flows countercurrent with lean glycol, which absorbs the water vapor from the hydrocarbon gas. The rich glycol is collected in the bottom of the Glycol Contactor and flows to the Glycol Regeneration Skid where rich glycol is regenerated to lean glycol by boiling off the water vapor.

The dry gas flows from the Glycol Contactor to the HP Gas Compressor, a single stage electrical driven centrifugal gas compressor. The HP Gas Compressor compresses the gas to 180 barg, the required pressure for gas lift. The hot compressed gas is cooled in the HP Discharge Cooler. The anti-surge and recycle of the HP Gas Compressor is taken upstream of the HP Discharge Cooler and flows back to the 2nd Stage MP Discharge Cooler.

The cooled gas flows to the gas lift header, any gas not required as lift gas is exported to the gas export pipeline.


Water Injection
To maintain the pressure in the reservoir water is often injected into the reservoir. The prime source of the injected water is seawater, but produced water could be reinjected as well. The description below
describes a typical seawater injection system.

The seawater injected into the reservoir is either cold seawater directly form the seawater lift pumps or hot seawater used for cooling prior to flowing to the water injection system. The seawater is filtered to remove particles of the seawater with Coarse Filters to 80 microns. The Fine Filters downstream of the Coarse Filter will assure deep filtration down to 2-5 microns. The filtered seawater is deaearated, oxygen removal, in the Deaearator. Vacuum Pumps and Ejectors will create vacuum in the Deaerator and remove the majority of the oxygen. Typically a Deaerator will achieve 50 ppb residual oxygen content. A common specification for injection water is 10-20 ppb. This is achieved by injecting oxygen scavenger into the injection water.

The filtered and deaerated seawater can be injected in the reservoir by increasing the pressure through pumping. The Water Injection Booster Pump increases the pressure 5-8 barg to assure sufficient NPSH for
the injection pumps. The Water Injection Pump increases the pressure to the required injection pressure, typically 200-300 barg. The injection water is then distributed to the subsea water injection wells.


Utilities
The topside oil, water and gas processing equipment require the following utilities:

Power Generation
An electrical power plant on the topside supplies usually electrical power during normal operations. The power is usually generated from gas turbine driven generators fuelled with fuel gas and diesel. Back-up and emergency power generation is provided.

HP and LP Flare system
The HP (high pressure) and LP (low pressure) flare system collect discharges from discontinuous sources as relief valves and blow down valves, as well as continuous sources such as the flashed off gas from the Produced Water Degasser and spill-off control valves in the LP and MP gas system. The sources are routed to the LP or HP flare depending on their operating and design pressure.

Fuel gas
The compressed MP gas can be used as fuel gas to fuel gas turbines for power generation. A lower pressure fuel gas, MP gas from the production separator is used to heat heating medium in a gas fired
heater or generate steam in a steam boiler.

Seawater
Seawater supplied to the topside by seawater lift pumps is used for cooling, fresh and potable water generation and to supply seawater to the water injection system.

Cooling
A closed cooling water system, water/MEG mixture, is often used to cool the hydrocarbon gas coolers. The cold cooling water cools the process medium in the heat exchanger. The hot cooling water is cooled by
exchanging the heat in a seawater/cooling water heat exchanger.

Heating
The well fluids and other heat consumers are heated by hot water or by steam. In some cases steam is generated and used to heat the process heat consumers. In other cases a hot water system is selected. In
case of a steam system the steam is generated by a waste heat recovery system on the gas turbine drivers of the power generation plant and/or steam boilers. In case of a hot water system the hot water is
generated by waste heat recovery system on the gas turbine drivers of the power generation plant and/or gas fired heaters.

Nitrogen
Nitrogen is usually generated from compressed air in membrane units and used for maintenance purging of vessels and piping systems.

Instrument Air
Instrument air is compressed, filtered and dried air that is used to operate control valves, shutdown and blow down valves.

Diesel
Diesel is used as a back-up fuel for fuel gas to generate power. Diesel is also used to drive the firewater pumps.

Firewater
Firewater is supplied to the topside to spray large quantities of water on the topside hydrocarbon containing vessels, piping and modules to prevent escalation in case of a fire or gas leak. Firewater is
seawater pumped to the topside firewater distribution system.

Chemicals
Chemicals are required for the production of oil, produced water and hydrocarbon gas. These chemicals are:

• demulsifier is used to break stable emulsions in the separation plant that will negatively influence the performance of the separators

• anti-foam is injected into the well fluid to prevent the formation of foam in the separators

• corrosion inhibitors are injected into oil and hydrocarbon gas stream to prevent limit corrosion of carbon steel

• asphaltene/wax inhibitors are injected mainly subsea to prevent or limit asphaltene and/or wax formation in subsea flow lines and pipelines.

• de-oiler or reverse demulsifier is injected into the produced water to improve the quality of the produced water

• methanol is injected subsea in the wells and the flow lines (for start-up and shutdown) as well as on the topsides in the high pressure hydrocarbon gas coolers (for start-up) to prevent hydrate
formation

• scale inhibitor is injected to prevent scale or limit scale formation


To assure the specification of the injected water is made chemicals are required as well:

• hypochlorite or chlorine to limit biofouling in the seawater system and to improve the performance of the fine filters

• poly-electrolyte and coagulant are injected into the seawater upstream of the fine filters to improve filtration

• oxygen scavenger is injected into the deaerator to achieve the required specification

• biocide is injected into the deaerated seawater on a shock dosing basis to prevent SRBs (Sulphate Reducing Bacteria) and associated corrosion. Biocide is injected on a shock dosing basis in the
seawater system as well.

• scale inhibitor is injected with the injection water into the reservoir to prevent scale formation in the reservoir.

• anti-foam may be injected upstream of the Deaerator to prevent foaming in the Deaerator.


Drains

The topside is equipped with an "open drains" and a "closed drains" system. The closed drains system collects all discharges from pressurised vessels, piping and other equipment. This is usually for maintenance or inspection reasons but could be continuous as well provided these stream are small. The open drains systems, separated in a hazardous and non-hazardous open drains system collects spillage from drip pans, funnels, etc.
















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