Summary

The well Spearman 23-5 is being considered in this problem. The well is currently

producing via the annulus with an oil flow rate of 170 – 240 bbl/day. The gas oil ratio is 1000

scf/stb. No water production has been found at the moment. Most of the production is expected

to be a result of the perforation D-4 whose depth ranges from 7852 ft to 7858 ft. Casing ID is 4.5

inch. Tubing ID is 1.995 inch and tubing thickness is 0.19 inch. Gas oil ratio is estimated at 100

scf/stb. The oil API is 33.5.

The goal of this project is to analyze the pressure drop of the fluid flow in the casing

versus the tubing to see whether the casing flow should be maintained or substituted by the

tubing flow. In order to achieve this goal, several parameters such as fluid properties, down-hole

temperature, flow patterns need to be included to best approximate the pressure drop of the fluid

flow. Parameters that are missing will be assumed as stated in this report.

Procedures

The gas is assumed to have a specific gravity of 0.64. Preliminary assumptions,

calculations and tests lead to the estimation that the well flowing pressure ranges from 2200 psi

to 2750 psi. These values for the well flowing pressure, along with the fluid flow rates and fluid

properties, can be used to help calculate 1) the gravitational and frictional pressure loss of the

fluid and 2) the pressure of the arriving fluid of the surface. Better results can be achieved with

smaller increment. For example, the inputs at the depth of 7855 ft will be used to calculate the

pressure loss at that depth. This calculated pressure loss is very likely to be applicable at a

similar depth, say, 7850 ft because the fluid properties have not changed much (fluid properties

are functions of pressure and temperature, both of which change as the fluid flow from the

perforations to the surface). However, the same calculated pressure loss is very likely to be

erroneous at a much smaller depth, say, 5000 ft because obviously, the pressure and temperature

of the fluid have been dropped significantly. The calculation procedure can be summed up as

follows:

- Input fluid properties, flow rates, inlet pressure, pipe materials, pipe dimensions, and

vertical depth.

- The calculation starts at the bottom hole, which is assumed to be at 7855 ft. This

starting position is called point 1.

- Fluid flow rates, fluid properties, pipe materials, and pipe dimensions help determine

both the frictional losses and gravitational pressure gradient of the fluid.

- Subtract the pressure loss from the inlet pressure at point 1 to obtain the pressure at

point 2 (Point 2 should be not too far away from point 1, for the reason explained

above. A good example for where point 2 should be is 7850 ft, or 7840 ft. The closer

point 2 is to point 1, the better the results, but the longer the calculation procedure is

also going to be). The pressure at point 2 is used to calculate the fluid properties at

point 2 and pressure loss from point 2 to point 3.

- Repeat the pressure loss calculation procedure above until the fluid arrives at the

surface.

On a side note, the temperature also affects the fluid properties but no temperature

information is available. Thus, a temperature of 220oF at the bottom hole, 80oF at the

surface, and a linear temperature gradient are assumed.

Results and Discussions

The calculation results show that a bottom hole flowing pressure range of 2200 psi to

2750 psi is not adequate to maintain a flow rate of 240 bbl/d. To accommodate for this, a

reverse procedure has been carried out: the wellhead pressure (i.e. the pressure of the

fluid arriving at the surface) is assumed to be 200 psi. From this wellhead pressure, the

pressures at increasing depths can be calculated, until the 7855 ft depth has been reached.

Figure 1 and Figure 2 illustrate the calculation results graphically. In Figure 1 (flow in the

casing scenario), it can be seen that in order to for the fluid to arrive at the surface at 200

psi, the pressure at the inlet condition (at 7855 ft) needs to be around 1700-1900 psi. On

the other hand, Figure 2 (flow in the tubing scenario) shows that the inlet pressure

requirement is only about 1300 psi. This means that the pressure loss is more significant

in the casing: a 400-500 psi difference.

To minimize pressure loss, it appears that a tubing flow should be more preferred

over a casing flow.

Figure 1. Flow in the casing

Figure 2. Flow in the tubing