4 Nov, 2014

Impact of Solution Gas on Crude Oil Properties in a Gathering Line

In the October 2014 Tip of the Month (TOTM), we demonstrated that Gas-Oil-Ratio (GOR) has a large impact on the capacity of crude oil gathering lines. In general as GOR increased the pressure drop increased which lowered the line capacity. In addition, at high pressures and low GOR, pressure drop was lower than the pressure drop for dead oil (solution gas is zero) because the viscosity of live oil is lower than viscosity of dead oil. This effect was bigger for the smaller line diameter.

In this TOTM, we will study the impact of solution gas (RS) on the crude oil properties in the gathering systems for one of the cases presented in the October 2014 TOTM. Specifically, the variation of the crude oil relative density and viscosity with the solution gas (RS) will be studied. Finally, the impact of solution gas (RS) on the oil and gas velocity and pressure drop along a gathering line for nominal pressure of 6900 kPag (1000 psig) and nominal pipe size of 101.6 mm (4 inches) will be demonstrated using multiphase rigorous method from a commercial simulator. The calculated properties, oil and gas velocities and pressure drops are presented in graphical format as a function of the oil stock tank volume flow rate and solution gas, RS.

For clarity, gas-oil-ratio (GOR) is defined as the total volume of gas which comes out of oil at standard conditions divided by the total volume oil at the stock tank conditions. The solution gas (RS) is defined as the volume of gas dissolved in oil divided by the volume of oil (with the same unis as GOR) but at the flowing temperature and pressure.

Case Study

For the purpose of illustration, we considered a case study for transporting a crude oil of relative density of 0.852 (°API = 34.6) at stock tank conditions combined with a gas with relative density of 0.751. The selected GORs were 0 (dead oil), 17.8, 35.6, and 89 Sm3 of gas/STm3 of oil (0, 100, 200, 500 scf/STB). The compositions of oil and gas are presented in Table 1. The oil C6+ was characterized as 30 hypothetical single carbon number (SCN) [1] ranging from SCN6 to SCN35 while the gas C6+ was characterized by 10 hypothetical SCN ranging from SCN6 to SCN15. For details of the SCN components, see Table 3.2 on page 64 of reference [1]. The mole fraction of SCN components were determined by an exponential decay algorithm [2].

 

Table 1. Feed composition at stock condition

table1

 

The following assumptions were made:

  1. Steady state conditions
  2. The line is 1.601 km (1 mile) long with nominal size of 101.6 (4 inches), onshore buried line.
  3. Segment lengths and elevation changes are presented in Table 2 and Figure 1. This elevation profile is considered to be approximately equivalent to “rolling” terrain.
  4. Pipeline inside surface roughness of 46 microns (0.046 mm, 0.0018 inch)
  5. Line nominal pressure 6900 kPag (1000 psig)
  6. The feed enters the line at 15.6 ̊C (60 ̊F)
  7. The ground/ambient temperature, is 15.6 ̊C (60 ̊F)
  8. Water cut is 0 (no water in the feed).
  9. Overall heat transfer coefficients of 2.839 W/m2- ̊C (0.5 Btu/hr-ft2- ̊F), for onshore
  10. buried line (minor effect as inlet temperature = ambient ground temperature).
  11. Simulation software ProMax [3] and using the Soave-Redlich-Kwong (SRK) Equation of State [4] for vapor-liquid equilibrium and Beggs-Brill method for two-phase pressure drop calculation [5].

     

Table 2. Line segment length and elevation change

table2

 

Figure 1. Gathering line elevation profile

fig1

 

Results and Discussions:

The two phase (oil and gas) flow through the gathering line was simulated by ProMax with SRK EOS for vapor-liquid equilibria and Beggs-Brill for two phase pressure drop calculations. Figures 2A and 2B present the calculated pressure drop per unit length as a function of oil stock tank volume rate and GOR for nominal line diameter of 101.6 mm (4 inches) at nominal line pressure of 6900 kPag (1000 psig) in SI (international) and FPS (Engineering) system of units, respectively. Figures 2A and 2B indicate that as the GOR increases from 0 to 35.7 Sm3/STm3 (0 to 200 scf/STB), the pressure drop decreases but increases with further increase in GOR of 89 Sm3/STm3 (500 scf/STB) and higher.

The impact of RS on the properties of oil is demonstrated in the next section which will explain the causes of pressure drop.

fig2a

Figure 2A (SI). Variation of pressure drop per unit length with oil stock tank volume rate and GOR at 6900 kPag for 101.6 mm pipe diameter

fig2b

Figure 2B (FPS). Variation of pressure drop per unit length with oil stock tank volume rate and GOR at 1000 psig for 4 in pipe diameter

Figure 3 presents the bubble point pressure of the feed to the gathering line at 15.6 (60) as a function of solution gas. Figure 3 indicates that for the nominal line pressure of 6900 kPa (1000 psig), the feed is under saturated up to GOR of 51.8 Sm3/STm3 (290.5 scf/STB). For GOR greater than this value, the oil becomes saturated with gas and gas breaks out.

fig3-1

Figure 3. Bubble point pressure of the feed to the gathering line as a function of solution gas at 15.6 (60)

The variation of oil relative density along the line as a function of solution gas (RS), is presented in Figure 4. This figure indicates that as the RS increases, the oil relative density decreases. Figure 5 shows that as the RS increases, the oil viscosity decreases considerably. The reduction of viscosity causes pressure drop to decrease. The simulation results (Figure 3) indicated that for GOR less than 51.8 Sm3/STm3 (290.5 scf/STB), the flow is under saturated single liquid phase; however, for higher GOR the flow becomes saturated two phase (gas and liquid) which causes the pressure drop to increase. The increase in pressure drop due to higher GOR (and higher total flow rate) is more than the decrease in pressure drop due to reduction of oil viscosity as a result of solution gas. The net effect is higher pressure drop compared to dead oil (GOR = 0) pressure drop.

Figure 6 presents the variation of oil and gas velocity for two stock tank oil rate along the gathering line at 6900 kPag for 101.6 mm pipe diameter and GOR of 89.1 Sm3/STm3 (500 scf/STB). Figure 6 indicates that the oil velocity remains constant along the line but the gas velocity increases due to pressure drop in the line.

Figure 7 presents the impact of GOR on pressure drop along the gathering line at 6900 kPag for 101.6 mm pipe diameter. As it can be seen in this figure, for GOR less than 51.8 Sm3/STm3 (290.5 scf/STB) the pressure drop decreases as GOR increases but at higher GOR due to presence of two phase flow, the pressure drop increases. As the GOR increases further, the effect of elevation change diminishes compared to rise of pressure drop due to friction.

Conclusions

The following conclusions can be made based on this case study:

  1. If the oil is under saturated the increase in solution gas (RS), reduces the oil viscosity and causes the pressure drop to decrease. For saturated oil, the increase in GOR changes the single phase liquid flow to two phase gas-liquid flow and causes the pressure drop to increase and overcome the pressure drop reduction due to lower liquid viscosity.
  2. While increasing solution gas (RS) reduces the oil viscosity and relative density they remain almost constant along the line.
  3. While at higher GOR the flow becomes two phase, the pressure drop due to friction becomes dominant and overcomes the elevation changes. This is more pronounced in the longer lines.
  4. While oil velocity remains constant along the line, the gas velocity increases along the line.

fig4-1

Figure 4. Variation of oil relative density with solution gas (RS), Sm3/STm3 (scf/STB), along the gathering line at 6900 kPag for 101.6 mm pipe diameter

fig5-1

Figure 5. Variation of oil viscosity with solution gas (RS), Sm3/STm3 (scf/STB), along the gathering line at 6900 kPag for 101.6 mm pipe diameter

 

To learn more about similar cases and how to minimize operational problems, we suggest attending our PF45 (Onshore Gas Gathering Systems: Design and Operation), G4 (Gas Conditioning and Processing), PF81 (CO2 Surface Facilities), PF4 (Oil Production and Processing Facilities), and PL4 (Fundamentals of Onshore and Offshore Pipeline Systems) courses.

By: Mahmood Moshfeghian

Reference:

  1. Campbell, J.M., Gas Conditioning and Processing, Volume 1: The Basic Principles, 9th Edition, 2nd Printing, Editors Hubbard, R. and Snow–McGregor, K., Campbell Petroleum Series, Norman, Oklahoma, 2014.
  2. Moshfeghian, M., Maddox, R.N., and A.H. Johannes, “Application of Exponential Decay Distribution of C6+ Cut for Lean Natural Gas Phase Envelope,” J. of Chem. Engr. Japan, Vol 39, No 4, pp.375-382 (2006)
  3. ProMax 3.2, Bryan Research and Engineering, Inc., Bryan, Texas, 2014.
  4. Soave, G., Eng. Sci. Vol. 27, No. 6, p. 1197, 1972.
  5. Brill, J. P., et al., “Analysis of Two-Phase Tests in Large-Diameter Flow Lines in Prudhoe Bay Field,” SPE Jour, p. 363-78, June 1981.

fig6-1

Figure 6. Variation of oil and gas velocity for two stock tank oil rate along the gathering line at 6900 kPag for 101.6 mm pipe diameter and GOR of 89 Sm3/STm3 (500 scf/STB)

fig7-1

Figure 7. Impact of GOR, Sm3/STm3 (scf/STB) on pressure drop along the gathering line at 6900 kPag for 101.6 mm pipe diameter

Written on November 1, 2014 at 9:00 am, by