Vast tonnages of oil sands are now being transported as slurries in centrifugal slurry pumps as the first stage of the bitumen extraction process. Similarly sized pumps are also used to transport the tailings from the extraction process to the disposal locations.These pumps are generally large (some driven by 5,000 hp motors) and employed in such numbers that their operating costs have become significant considerations.
Total Costs
Actual costs vary enormously with different pump head, solids size and concentration. Energy, wear, capital and rotational assembly calculated costs are shown in Figure 2 (from Reference 1) for the conditions noted.
The specific speed of the pump is defined as:
[[{"type":"media","view_mode":"media_large","fid":"267","attributes":{"alt":"The specific speed of the pump is defined as","class":"media-image","height":"170","id":"1","style":"float: left;","typeof":"foaf:Image","width":"307"}}]]The typical oil sands pump operates around 8000-m3/h. The Cv = 40 percent or SG of 1.65 in Figure 2 is on the high side, but not untypical. Heads vary, but 50-m is typical. Maintenance labor costs are not included, nor is the effect of parts change out cycles.
Cost Breakdown
In the original study (Reference 2), an analysis of operating costs showed that in light wear service, energy costs were by far the largest component, while in medium to heavy service (Figure 3), wear parts replacement cost approached half of the total, with capital costs becoming almost insignificant.
Figure 2. Total Cost of Ownership (TCO) vs. pump specific speed for different flow rates
[[{"type":"media","view_mode":"media_large","fid":"268","attributes":{"alt":"Total Cost of Ownership vs. pump specific speed for different flow rates","class":"media-image","height":"170","id":"1","style":"float: left;","typeof":"foaf:Image","width":"307"}}]]Rotating costs are the estimated costs for the bearing housing, shafts, sleeves and stuffing box. In a solid transport application, such as the movement of oil sands tailings, the solids size and concentration are usually set by the process. Typical values would be a solids size (D50) of about 200 micron at a concentration by volume of 35 percent.
Limiting Wear Life
As noted in Reference 1, wear in the suction liner nose area usually causes a shutdown of the pump for parts replacement. If a component wear-out thickness is assumed, graphs of expected suction liner wear life in hours can be produced. If different duty heads are plotted against specific speed, then curves of suction liner wear life for different individual pump head per stage values may be shown for different specific speed designs (Figure 4).
Figure 4 clearly shows that lower specific speed designs and/or lower pump operating head per stage dramatically improve the wear life of the suction liner and therefore result in longer times between maintenance overhauls and shutdowns.
Downtime
If we take the cost for a typical oil sands tailings pump size of around 8,000-m3/h capacity from the above and convert the wear life axis (assuming 7,400 hours yearly operating time) into downtime occurrences per year, and convert different specific speed pumps of 8,000-m3/h size into single pump capital, we can display downtime occurrences relative to the pump head per stage and capital cost (from Reference 1), as seen in Figure 5.
Figure 2. TCO breakdown for a typical medium to heavy service.
[[{"type":"media","view_mode":"media_large","fid":"269","attributes":{"alt":"TCO breakdown for a typical medium to heavy service.","class":"media-image","height":"170","id":"1","style":"float: left;","typeof":"foaf:Image","width":"307"}}]]The capital cost here is just the bare pump. A more realistic capital cost would be the installed cost, which will be 4 to 6 times the cost of the pump plus drive train, or perhaps 10 to 15 times the cost of the bare pump alone.
Capital Cost and Downtime Cost
Operation at lower head per stage requires more pumps and more capital. If we consider a typical tails line that requires 250-m of head that could, for example, be operated by five pumps producing 50-m of head each (or a greater or lesser number), and if we assume for simplicity's sake that downtime occurrences each cost $1 million, then we can produce a plot of downtime cost verses initial (bare shaft) pump capital, as shown in Figure 6.
The cost of downtime is directly proportional to the price of oil, which is steadily increasing. The cost of downtime based on a production rate of 8,000-t/h and $30/bbl for the value of bitumen was $150,000 per hour when Reference 1 was written. The value of bitumen is at least $40/bbl now, so depending on how long you assume for the outage the cost is easily calculated. A number of $2 million is much closer than $1 million mentioned earlier.
It is interesting to note that the different head per stage possibilities (35-, 50- and 65-m) essentially make one line, where increasing pump capital decreases the incurred downtime cost. Increasing the capital costs from bare pump to installed cost (as noted earlier) should not change this chart except for the scale of the x axis.
Figure 4. Suction liner wear life vs. pump specific speed.
[[{"type":"media","view_mode":"media_large","fid":"270","attributes":{"alt":"Suction liner wear life vs. pump specific speed.","class":"media-image","height":"170","id":"1","style":"float: left;","typeof":"foaf:Image","width":"307"}}]]In the middle region of the graph, an increase in bare shaft pump capital of $250,000 provides a downtime reduction of around $2,000,000, or a payback of three months. In the case of the installed cost, the payback period will be extended.
Pumps require additional capital for gearboxes, motors, electric supply, etc. Fewer lower specific speed (higher head) pumps will require less capital per pump, so it would seem lower specific speed would have an advantage over lower head per stage-except for the shell wear and cost. This will ultimately be limited by the width and spheres passage, so head per stage will also have to be utilized.
Conclusion
Costs are expected to vary significantly with the service conditions. Energy costs are almost always the highest. In a heavy duty service, wear parts cost can be as much as 40 percent of the total, and pump capital and other costs are usually 5 percent or less.
Assuming a given duty, solids size and concentration, downtime is dictated usually by the pump front suction liner, which is related to pump (design) specific speed and head per stage.
Specific speed and head per stage relate to pump capital in a similar way and increases in pump capital can be shown to dramatically reduce downtime costs.
Pumps & Systems, June 2008
Figure 5. Downtime Occurrances vs. Capital Cost (as a function of head per stage)
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References
1. Addie, G. R., Sharpe, J. (2007): "Oilsands Slurry Pump Wear, Operating, and Downtime Costs," Oil Sands Heavy Oil Technology Conference, Calgary, Canada, July 18-20, 2007.
2. Sellgren A., Addie G.R., Visintainer R, Pagalthivarthi K. (2005): "Prediction of slurry pump component wear and cost," Proceedings, WEDA XXV and Texas A& M Annual Dredging Seminar, New Orleans, U.S.A., June.
3. Wilson, K.C., Addie, G.R., Sellgren, A. and Clift, R. (2006) Slurry Transport Using Centrifugal Pumps, 3rd edition, Springer, New York, U.S.A, 435 p.
Figure 6. Downtime Cost vs. Capital Cost (as a function of head per stage)
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