Processing plant

The present section goes through the presentation of the several sub-systems implemented on a typical oil and gas platform (Figure 2.1).

Production

manifolds Separation treatmentOil

Recompression Gas treatment Fuel gas handling Produced water injection Gas Oil/Condensate Condensate/NGL treatment Fuel gas Condensate/ NGL Well streams Gas import Seawater injection Water discharge Injection water Seawater Processing plant Processing plant

Gas turbines Waste heat recovery

Air Flue gases

Flue gases

Power and heat generation

Power and heat generation

Power Heat

Injection water

Figure 2.1: A general overview of an oil and gas platform.

Production manifold

The reservoir fluid is transferred to the platform complex via a network of pipelines and a sub-system of production manifolds operating at different pressure levels. The individual well-streams pass through choke boxes, which consist of valves and chokes, in which they are mixed and depressurised to ease further gas and liquid separation in the separation train. Ethylene glycol and methanol may be added to prevent freezing. The operating settings for each well are fixed to ensure an optimum production and recovery rate.

Separation

Oil, gas and water are separated by gravity (Figure 2.2) in a certain number of stages (2–3 for North Sea platforms and 4–5 for Gulf of Mexico facilities). Well-streams from the high-pressure manifold enter the 1st stage separator, while the ones from the low-pressure manifold may be routed to the 2nd stage. A fraction of the well flows may be processed in a test separator to allow for detailed flow measurement and analyses. Since low pressures and high temperatures

Separation Produced water

Valve Heater Separator

Oil (treatment) Gas (to recompression)

Gas (to treatment)

Well-fluid (from LP manifold) Well-fluid (from HP manifold)

Figure 2.2: A generalised overview of a separation sub-system.

ease the separation of these three phases, the pressure of the well-fluid is decreased in several stages by using throttling valves. In some cases, if the feed temperature is too low or if the oil is viscous, the oil temperature may be increased by preheating at the inlet of each stage, either before or after the de-pressurisation. The oil flow may be split into two or more streams, and only a fraction is then heated before entering the separator of the next stage, while the other fractions bypass the heater.

The separators can be either of the three-phase (gas/liquid/water) or two-phase (gas/liquid or liquid/liquid) type. The separator placed at the first separation stage is generally of the three- phase type, and it should be designed to ensure that minimum amounts of liquid are carried over with gas, that minimum quantities of hydrocarbons are transported with the produced water, and that the oil flow is adequately degassed and dry. The separators implemented at the other separation stages may be either two- or three-phase, depending on the processing plant and the oil properties. The separator placed at the last separation stage is generally a liquid/liquid separator, such as an electrostatic coalescer, and is designed to reduce the water content of the oil flow and to meet the export specifications.

Crude oil typically contains dissolved gases such as impurities (e.g. sulphur hydrogen H2S) or

low and medium-weight hydrocarbons (e.g. methane CH4). These gases should be removed

to avoid corrosion issues in storage tanks or pipelines, which, in other words, means that the oil should be stabilised and that its vapour pressure should be decreased. It may be controlled by heating the oil flow at the inlet of the final separation stage, which operates at nearly-atmospheric conditions, to remove the remaining volatile components.

Oil treatment

The oil from the separation section enters the oil treatment and export sub-system (Figure 2.3), after having been mixed with the heavy hydrocarbons that are removed in other parts of the processing plant. It is then pumped and either stored in a tank, where the last traces of gas and water are removed by flashing, or directly exported onshore.

Cooler Oil treatment Oil (from separation) Pump Oil (to storage or export)

Figure 2.3: A generalised overview of an oil treatment sub-system.

Condensate treatment

In some cases, the typical processing scheme, which combines multi-stage separation and multi-stage recompression sub-systems, may not be sufficient to reach the desired oil export specifications. A more complex processing scheme may then be integrated to control the vapour pressure, by for instance integrating a separate condensate treatment section (Fig- ure 2.4). This sub-system may consist of a stabiliser, where the condensate recovered from the several compression stages is treated apart to allow for a better separation between the light- and medium-weight hydrocarbons, and of a dehydrator and other scrubbers.

Condensate treatment Cooler Condensate (from treatment) Pump Condensate (to gas)

Condensate (to oil)

Wet gas (to treatment) Column

Dry gas

Decanter

Recompression

The gas recovered from each separator, excluding the first one, enters the recompression sub- system (Figure 2.5). It generally consists of several stages, each stage processing the gas from the previous stage, and in some cases, from other parts of the processing plant. A typical stage consists of a cooler, a scrubber and a compressor. The cooler and scrubber ensure that the gas temperature and hydrocarbon content are low enough to avoid a too high power demand of the compressors, as condensate and water droplets are condensed and removed, while avoiding hydrate formation. The gas exiting the recompression process has approximatively the same pressure as the feed, and it is mixed with the gas from the 1st separation stage before entering the gas treatment section.

Gas (to treatment) Compressor Cooler

Recompression

Gas (from separation) Condensate (to separation)

Valve Scrubber

Figure 2.5: A generalised overview of a recompression sub-system.

Gas treatment

As for the recompression sub-system, the gas treatment also consists of several stages, each including a heat exchanger, scrubber and compressor. In some cases, there may be a dehy- dration stage (Figure 2.6), in which the water content of the gas streams is reduced to prevent further hydrate formation in the pipelines. Wet gas enters a packed contactor, in which water is captured by physical absorption, using an hygroscopic solvent such as liquid triethylene glycol (TEG). The water content of the gas after this dehydration is usually below 0.01 mol. %. The wet glycol is depressurised and cleaned of water vapour in a desorption column, quipped with a condenser and a reboiler. Regenerated glycol is pumped, preheated and reintroduced into the absorber. Most dry gas is further compressed, where it is cooled and scrubbed to further remove heavy hydrocarbons, and compressed for storage and possibly export.

Fuel gas handling

A fraction of the produced gas may be used for on-site power generation after processing in a fuel gas handling sub-system (Figure 2.7). It is most often heated, scrubbed and then expanded through a succession of valves, before final combustion with air in gas turbine engines.

Gas (from treatment) Cooler Gas dehydration Valve Column Scrubber

Gas (to flaring)

Condensate (to separation)

Gas (to treatment) Kettle reboiler

Figure 2.6: A generalised overview of a glycol loop sub-system.

Gas (to turbines)

Heater

Fuel gas handling

Valve Scrubber

Gas (from separation or treatment)

Condensate (to separation) Gas (to flaring)

Figure 2.7: A generalised overview of a fuel gas handling sub-system.

Produced water treatment

The water from the separation and purification trains, also denoted produced water, enters hydro-cyclones in which suspended particulates and dissolved hydrocarbons are removed. It then passes through valves and flows through degassers where the last oil and gas traces are recovered before disposal to the sea.

Seawater injection

In parallel with the oil and gas processing, seawater may be treated on the platform for further injection into the reservoir, in order to sustain high pressure conditions. The injection fluid must meet strict quality requirements to prevent corrosion and reservoir degradation: it is thus cleaned before being pumped into the reservoir, using a succession of filters to remove solid impurities such as sand particles and algae.

2.2.3 Utility plant