In the previous segments of this series, I explained how process control can improve the safety of fracking, off-shore drilling, well blow-out prevention, drilling ship stability, etc. These articles were dealing with specific parts of the overall oil production process. Now I will walk through the whole process from beginning to end.
I am not in favor of the staggering investments in these processes, but if we are going to scrape the bottom of the fossil fuel barrel, at least we should do it safely.
The Overall Process
Once the test wells identify the depths at which the oil/gas bearing zones are located, the operation begins. It consists of three phases: 1) drilling, 2) production and 3) closing or killing the well. (For a description of killing the well, see Phase 3 at the bottom of this article). Looking at the equipment used in this process (Figure 1), this industrial process might appear to be very complex and, therefore, hard to control. In fact it is simple!
The control goal is simply to balance the variable pressure at the bottom of a vertical U-tube with the pressure of a fluid which is circulated in it. The fluid pressure at the bottom of the U-tube is adjusted by changing the pump discharge pressures and by changing the hydrostatic head on the bottom of the U-tube through the adjustment of the density of the circulated fluid.
Phase 1 starts with drilling the bore hole (~ 36 in. dia.) by lowering a drill bit into the well and rotating it by a shaft inside a vertical drill pipe (~ 6 in. dia.). Through this pipe drilling fluid is pumped down, serving the dual purposes of cooling the bit and carrying up the "cuttings" to the rig, through the annulus (or annular) between the pipe and the bore hole. As the drilling progresses, a number of casings are installed for support, and a number of blow out preventers (BOP) are added, so that if excessive pressure is encountered, the well can be closed.
During Phase 1, the goals are
- To keep the flow velocity and pressure at the bottom (PB in Figure 2) high enough to carry the cuttings up. This pressure ranges form 5000 to 10,000 psig.
- To keep the PB higher than the oil/gas pressure (PO) in the formation. This safety margin (ΔP = PB – PO) should be held at about 500 psig.
- To keep the PB pressure by some 500 psig below the pressure (PF) at which the drilling fluid would start to escape into the wall of the borehole by fracturing it (PB < PF – 500 psig).
- To protect against a "blow-out" that can occur if high pressure gas pockets are encountered during drilling.
In order to satisfy the requirements 1), 2) and 3), all that is needed is to maintain a pressure balance. This balance must also consider the hydrostatic heads in the drill pipe (Hd) and in the annulus (Ha), plus the friction losses as the drilling fluid moves through the drill pipe (Fd), the rig and the annulus (Fa). The hydrostatic heads (H) are the product of the depth (D) of the well and the density (r) of drilling fluid (H = Dr), which in a 10,000 ft. well is about 5000 psig. Based on the accurate measurements of these values, the required drill pipe and annulus pressures (Pdp and Pa) and the corresponding drill fluid pump suction and discharge pressures (PS and PD) are easily calculated as:
Pdp ~ PD = PO + ΔP + Fd – Hd
Pa ~ PS = PO + ΔP – Fa – Ha
Once they are accurately measured, all that is needed is to satisfy the relationship:
PF > PB = PO + ΔP
In order to satisfy requirement 4) above, the system also must be able to detect both the developments of "kicks" and initiate the response to them. The development can be detected by noting an increase in the flow from the well (usually Coriolis meters are used to measure the flows — F in Figure 2) by the rise in the level in the "mud tank" (L) and by the rise in the drill pipe and annulus pressures (Pdp and Pa). The critical measurements, therefore, are the pressures, densities and flows as shown in Figure 2.