Crude Oil Pipeline Control

The pumping station delivers crude oil to the pipe line, and has two pumping stages, booster and main (each one in a redundant configuration—two operative and one cold standby—with a total capacity of 300 KBPD). All pumps (both boosters and mains) are of the positive displacement type. The boosters are 1200 hp and the mains are 3000 hp each. Each pump has its own hydrodynamic speed driver for velocity control whose setpoint is provided by a selector control between the total flow and the discharge pressure for the booster pumps. For the main pumps, the selector is between the total flow, the suction pressure and the discharge pressure, and, therefore, the controller with the lowest demand will set the velocity to the respective pump. Our questions are as follows:

1. For a pumping configuration with reciprocating pumps in series, each one with its own speed control, is it possible to maintain an accurate and stable pressure control just using speed control?  
2. If a booster pump or a main pump shuts down, would this control system be able to respond in time in order to maintain pressure balance on the system?
3. Someone suggested to us to include a control pressure valve to recirculate oil at the intermediate manifold between boosting stage and main stage, which will fast-actuate in order to stabilize the pressure if needed. Would this work?

We appreciate your suggestions and critique. There is too much debate here at my company about this point.

Luis Fernando Betancur
lbetancur@tipiel.com.co

A: You are right, Chapter 8.34 in Vol. 2 does not answer all your questins, you also have to read Chapters 7.4 and 8.35 to get the full picture.

Your solution of using variable-speed (VS) positive displacement (PD) pumps, instead of throttling bypass control valves, is the correct one, because the pipeline process is a mostly friction one, and you would be wasting a lot of energy in the form of valve pressure drops. With PD pumps, cavitation also is less of a problem.

As to installing a recirculating control valve back to the supply tank from the intermediate manifold, this is reasonable if you want to mix the tank contents before start-up (to reduce settling and achieve uniform density) or to gradually increase the booster discharge pressure during start-up to the required inlet pressure of the main pumps before they are started, but not for normal operation. The relief valves should take care of overpressures. You need those plus blocks and check valves on each pump. In addition to the pressure safety valve (PSV) opening in the bypass, the booster pumps have to shut down any time the main pump trips, and, similarly, the main pumps have to trip to prevent the development of low suction pressure, when the boosters trip.

I assume you have selected the booster pumps that require a minimum inlet pressure (net positive suction head required, NPSHR) that is lower than the net positive suction head available (NPSHA). To determine this minimum, you determine NPSHA using the minimum possible supply tank level and oil density in combination with the maximum oil density expected.

The purpose of the booster pump is to keep the main pump suction pressure constant by compensating for supply tank level, viscosity, etc. If we understand "the personality"of the pipeline process, the required controls become fairly obvious. As you can see in Part A of Figure 1, the pump curves (in red) of all VS-PD pumps are very steep parallel lines, because flow changes very little, even with large changes in discharge pressure. If you have a pair of pumps in parallel, pump flows are added (Part B), and if you have a pair of pumps in series, pump pressure is added (ΔPs are added in Part C). In your case, you have both series and parallel operations (Part D), so the combined pump curves are as shown by the parallel red lines. For sake of this  illustration, I have assumed that all pumps are the same (which obviously is not the case), but it simplifies the explanation.

Pumps in tandem

Figure 1. The pump curves (red) of various combinations of positive displacement pumps are displayed on plots where the abscissa is flow in % of the maximum capacity of one pump, and the ordinate is pressure in % of the maximum discharge pressure of one pump. Blue is the system curve (pressure-flow relationship) of the pumping station, and where the blue and red lines cross is the operating point. Once we control one of the variables (flow or pressure), the other one is fixed.

Because your process is a "mostly friction" one, with only a small elevation ("static head") component, your system curve is basically a parabola (blue in Part D). If you select an operating point on Part D by controlling the discharge pressure (or flow) at a particular value, you have, in effect, also set the other. For example, in the sketch, I have picked a flow controller (FIC) setpoint which equals 120% of the full capacity of one pump. This automatically sets the discharge pressure also P3 = 50% of one pump) and the speed at 63%.

Obviously, in your actual configuration the four pumps are not the same, (the main pumps are nearly three times as powerful as the boosters) and, consequently, the combined pump curves will be different from the ones I have shown in Part D, but the concept is the same.

Now, let me turn to the control of the the pumping station. If you want only stable operation, you can modulate the speed of the booster stage to maintain the suction pressure for the main stage, and can throttle the speed of the main stage to keep the discharge (flow or pressure) constant. This, with safety limits and start-up/shutdown logic is all you need.