Production Facility Part 2
The oil and emulsion from the separators must be treated to remove water. Most oil contracts specify a maximum percent of basic sediment and water (BS and W) that can be in the crude. This will typically vary from 0.5% to 3% depending on location. Some refineries have a limit on salt content in the crude, which may require several stages of dilution with fresh water and subsequent treating to remove the water. Typical salt limits are 10 to 25 pounds of salt per thousand barrels.
Figures 1-7 and 1-8 are typical direct-fired heater-treaters that are used for removing water from the oil and emulsion being treated. These can be either horizontal or vertical in configuration and are distinguished by the fire tube, air intakes, and exhausts that are clearly visible. Treaters can be built without fire tubes, which makes them look very much like separators. Oil treating can also be done by settling or in gunbarrel tanks, which have either external or internal gas boots. A gunbarrel tank with an internal gas boot is shown in Figure 1-9. Production facilities must also accommodate accurate measuring and sampling of the crude oil. This can be done automatically with a Lease Automatic Custody Transfer (LACT) unit or by gauging in a calibrated tank. Figure 1-10 shows a typical LACT unit. The water that is produced with crude oil can be disposed of overboard in most offshore areas, or evaporated from pits in some locations onshore. Usually, it is injected into disposal wells or used for waterflooding. In any case, water from the separators must be treated to remove small quantities of produced oil. If the water is to be injected into a disposal
well, facilities may be required to filter solid particles from it.
Water treating can be done in horizontal or vertical skimmer vessels, which look very much like separators. Water treating can also be done in one of the many proprietary designs discussed in this text such as upflow or downflow CPIs (Figure 1-11), flotation units (Figure 1-12), crossflow coalescers/separators, and skim piles. Skim tanks with and without freeflow turbulent coalescers (SP Packs) can also be used. Any solids produced with the well stream must also be separated, cleaned, and disposed of in a manner that does not violate environmental criteria. Facilities may include sedimentation basins or tanks, hydrocyclones, filters, etc. Figure 1-13 is a typical hydrocyclone or “desander”
The facility must provide for well testing and measurement so that gas, oil, and water production can be properly allocated to each well. This is necessary not only for accounting purposes but also to perform reservoir
studies as the field is depleted. The preceding paragraphs summarize the main functions of a production facility, but it is important to note that the auxiliary systems supporting these functions often require more time and engineering effort than the production itself. These support efforts include:
1. Developing a site with roads and foundations if production is onshore, or with a platform, tanker, or some more exotic structure if production is offshore.
2. Providing utilities to enable the process to work: generating and distributing electricity; providing and treating fuel gas or diesel; providing instrument and power air; treating water for desalting or boiler feed, etc. Figure 1-14 shows a typical generator installation and Figure 1-15 shows an instrument air compressor.
3. Providing facilities for personnel, including quarters (Figure 1-16), switchgear and control rooms (Figure 1-17), workshops, cranes, sewage treatment units (Figure 1-18), drinking water (Figure 1-19), etc.
4. Providing safety systems for detecting potential hazards (Figures 1-20 and 1-21), fighting hazardous situations when they occur (Figures 1-22 and 1-23) and for personnel protection and escape (Figure 1-24).
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