As seasons change and the outside temperature begins to warm up, there is a potential processing change to be on the lookout for. Crude purchasing can often be overlooked – the commercial Crude Buyer/Scheduler is always looking for “opportunistic” crude for purchased feed stock to the refinery to show an increased profit margin. The Crude Buyer interfaces with the refinery scheduler and Operations who work to process the different purchased crude by blending them with “good” crude and making unit operating adjustments.
The refinery most likely has a “management of change” (MOC) regarding crude purchases. There are EPA VOCs regulations limiting floating roof tanks to only storing crude oil with vapor pressures less than 11.0 psia. However, crude transfer pumps usually set the crude tanks’ minimum operating level settings with their NPSH requirements to prevent pump cavitation damage.
“Light” crudes are generally classified as crudes with specific gravities between 37 and 50°API (crudes above 50 to 52°API are “condensate” crudes). A survey study for the Dept. of Transport showed crude rail tank car RVP values averaging 8 psia for warmer times of the year and 12.5 psia during colder periods for light crudes such as Bakken, Eagle Ford, etc. A limiting RVP of 10 psia was reported as typical for crude oil transported via pipeline due to potential for pipeline pump cavitation. 
Crude shipments via underground pipelines may come in at 70°F; however, crude by rail car will come in at ambient temperature. Regardless, these light crudes most likely can only be processed in the Crude unit in blended portions with heavier crude and so will be stored in separate crude tanks. This separate storage combined with low transfer-out rates can result in long tank turnover times leading to crude tank temperatures closer to ambient than the “normal” crude tanks.
Many old original crude pumps at refineries are likely to have been designed for low 30’s API crudes with low vapor pressures. High vapor pressure crude plus transfer pumps designed for low 30’s API can lead to NPSH complications and potential pump cavitation damage. The refinery area engineer should proactively review the refinery crude selection limitations and their associated documentation, assumptions and associated calculations. Of particular concern would be a contractual year-round RVP limitation: A low value would restrict potential crudes during the winter; too high a value could create pump NPSH related cavitation damage during the warmest summer months.
The NPSHA (available) from the tank system and crude properties is calculated by the following equation:
- NPSHA = Available NPSH at pump suction, ft. of liquid
- Pi = Initial Operating Pressure, PSIA
- Pvp = Vapor Pressure of fluid at operating temperature, PSIA
- Z = Static head from liquid source elevation to suction of pump, ft.
- hf = Frictional pressure drop in suction pipe to pump, ft.
- (hf = 2.31 * ΔP(psi) / S.G.)
Consider the following example:
- Crude Tank: atmospheric floating roof (Pi = 14.7 psia)
- Minimum Operating Level: 7 ft.
- Summer tank temperature: 80 to 90°F
- Crude transfer pump (typical API data sheet and pump curve below):
- Flow: 440 GPM (~15,000 BPD)
- Discharge Pressure: 150 psig
- Speed: 3600 RPM
- NSPHR: 22.1 ft. (from pump curve)
- Suction Elev.: ~1.5 ft.
- Suction piping friction pressure drop: ~1.3 psi (hf = 3.5 ft.)
- Original pump design based on Intermediate Crude such as LLS (LA) or Norway Blend (Alvhein)
- Density: 35°API (SG60 = 0.85)
- RVP = 4 psia
- New pump conditions based on Light Crude such as Eagle Ford or Bakken:
- Density: 48°API (SG60 = 0.788)
- RVP = 8 psia
- NPSH standard safety margin: 2 ft. (to take into account other factors to keep away from incipient cavitation)
Using this information, a summary of the effect of new crude type with RVP of 8 psia and increasing tank temperature on Crude Transfer pump operation can be prepared:
For the “example pump”, a light crude such as Eagle Ford can be handled with no effect on crude tankage or pump for most of the year (storage temperatures less than 80°F). However, the effect of temperature on crude vapor pressure increases the potential for pump cavitation damage as the system temperature rises above 80°F (available NPSH less than required pump NPSH). To counteract this, the crude tank minimum operating levels and alarm settings would need to be increased by 2.8 to 4.0 ft (to 9.8 to 11 ft.). This would have the negative economic impact of decreasing crude tank “working capacity” by 10 to 14% for a 40 ft. tank (assumed maximum operating level ~35 ft.).
The effect of a higher RVP of 10 psia has a greater impact. Even at 75°F, for a 10 psia RVP crude, the available NPSH is 8 ft. less than the 8 psia RVP crude This would have the negative economic impact of decreasing crude tank “working capacity” by 25% for a 40 ft. tank (assumed maximum operating level ~35 ft.). essentially year-round. With this significant impact, a new low NPSH pump and motor maybe justified to recover the lost working capacity.
Note that pump NPSHR increases with increasing pump flow rate; see below. Therefore, another non-capital option would be to set a maximum limit and alarm at low enough flow rate to maintain the required pump NPSHR below the available NPSHA. However, reducing pumpout rate to reduce pump NPSHR will have a similar negative effect of limiting crude tank throughput, although possibly not as drastic as raising the minimum operating level on a 150 to 200 ft. diameter tank.
New high vapor pressure crude combined with transfer pumps designed for low 30’s API crude may create potential NPSH problems.
The need for higher available NPSH to prevent impending cavitation at the crude transfer pumps may require some of the following mitigations:
- Restrict shipments of light high RVP crude during hot summer months.
- Set Maximum flow rate limit and alarm for the Lt. Crude pump to maintain required its NPSHR below the available NPSHA.
- Review suction piping configuration and hydraulics for bottlenecks; every 1 psi of pressure drop decreases the available pump NPSH by about 2.9 ft.
- Install new low NPSHA pumps if long term
operating condition is justified.
- Pump NPSH is proportional to pump speed; 1800 RPM driven pumps have significantly lower NPSH requirements than 3600 RPM pumps.
It is also important to review Crude unit startup operation/ procedures. Extended startup with recirculated warm off spec streams to crude tanks could create elevated tank temperatures and vapor pressure problems. At one refinery, when start-up problems extended startup time, the crude tank handling unit recycle reached over 120°F. Review may indicate that temporary higher Minimum Tank Levels and Alarms may be necessary during startup.
 “A Survey of Bakken Crude Oil Characteristics Assembled for the U.S. Department of Transportation”, American Fuel & Petrochemical Manufacturers, by Dangerous Goods Transport Consulting, Inc., 2014