pipeline technology journal 15 industry and practice settling velocity, vs (m/s) vs = g (ρp - ρ) dp2 / (18 µ) where: ρp & ρ: densities of solid particle and liquid respectively, kgm/m3. dp: diameter of solid particle, micron meter. µ: continuous media viscosity, pa.s = 1000 c.p. critical velocity, vc is calculat- ed as per oroskar & turian [4] figure 2: critical flow rate versus pipeline presure loss, case 0.5 % bs vc = 1.85 [g d (s-1)]0.5 c0.1536 (1-c)0.3564 (d/d)-0.378 re0.09 x0.3 where: d = solid particle diameter, m g = earth gravitational, 9.81 m/s2 s = ratio of solid to liquid density c = solids volume fraction re = ρm vs d / µ figure 3: critical flow rate versus pipeline pressure loss, case 1.0% bs x = fraction of eddies with velocities exceeding the hindered settling velocity of the particles, taken as 0.75 2.5 conclusion particle size, micron meter critical flow rate, bbl/d 100 200 300 400 500 600 700 800 8,133 10,672 12,511 14,004 15,284 16,417 17,439 18,376 due to nature of project crude oil, has relatively low api, high viscosity and low flowing velocity, it’s recommended not to delay pigging operations behind five days, this subject depends also on the solid particle size. references [1] ken arnold & maurice stwewart 1989 “surface production operations, 2nd edition”, eq.(8-30), p. 272 [2] michael 2002. certified in plumbing engineering (cipe) and certified in plumbing design (cpd), “facility piping system handbook, 2nd edition” the mcgraw-hill companies inc.,” p. 1068 [3] pipe-flo stock user’s manual & method of solution, eq.15, p.19 [4] deposition velocities of newtonian and non-newtonian slurries in pipelines. table 1: sand particle size versus critical flow rate this means for example that with sand particle size 200 & 600 micron meter, flow rates up to 10,672 bbl/d & 16,417 re- spectively will settle sand. in figures 2 & 3 here-in under, plots for critical flow rates versus pipeline pressure loss. for example, pressure loss with no pigging when sand size is 600 micron will be 76 & 100 psi with bs = 0.5 & 1% respective- ly. it’s suitable to say that the calculations can be run for differ- ent bs % to get corresponding pressure loss in every case. author hesham a. m. abdou agiba petroleum company general manager in operations department heshamaabdou@gmail.com