Page 53 - Petroleum Production Engineering, A Computer-Assisted Approach

Guo, Boyun / Computer Assited Petroleum Production Engg 0750682701_chap03 Final Proof page 43 3.1.2007 8:30pm Compositor Name: SJoearun

RESERVOIR DELIVERABILITY 3/43
standing, m.b. Concerning the calculation of inflow per- Total compressibility, c t ¼ 0:000013 psi 1
formance of wells producing from solution gas drive Drainage area, A ¼ 640 acres (r e ¼ 2,980 ft)
reservoirs. J. Petroleum Technol. 1971; Sep.:1141–1142. Wellbore radius, r w ¼ 0:328 ft
vogel, j.v. Inflow performance relationships for solution- Skin factor, S ¼ 5.5
gas drive wells. J. Petroleum Technol. 1968; Jan.:83–92. 3.4 Construct IPR of two wells in an unsaturated oil
reservoir using generalized Vogel’s equation. The fol-
lowing data are given:
Problems Reservoir pressure, p ¼ 5,500 psia
p
Bubble point pressure, p b ¼ 3,500 psia
3.1 Construct IPR of a vertical well in an oil reservoir.
Consider (1) transient flow at 1 month, (2) steady-state Tested flowing bottom-hole pressure in Well A,
flow, and (3) pseudo–steady-state flow. The following p wf 1 ¼ 4,000 psia
data are given: Tested production rate from Well A, q 1 ¼ 400 stb=day
Tested flowing bottom-hole pressure in Well B,
Porosity, f ¼ 0:25 p wf 1 ¼ 2,000 psia
Effective horizontal permeability, k ¼ 10 md Tested production rate from Well B,
Pay zone thickness, h ¼ 50 ft q 1 ¼ 1,000 stb=day
p
Reservoir pressure, p e or p ¼ 5,000 psia 3.5 Construct IPR of a well in a saturated oil reservoir
Bubble point pressure, p b ¼ 100 psia using both Vogel’s equation and Fetkovich’s equation.
Fluid formation volume factor, B o ¼ 1:2 The following data are given:
Fluid viscosity, m o ¼ 1:5cp
p
Total compressibility, c t ¼ 0:0000125 psi 1 Reservoir pressure, p ¼ 3,500 psia
Drainage area, A ¼ 640 acres (r e ¼ 2,980 ft) Tested flowing bottom-hole pressure, p wf 1 ¼
Wellbore radius, r w ¼ 0:328 ft 2,500 psia
Skin factor, S ¼ 5 Tested production rate at p wf 1 ,q 1 ¼ 600 stb=day
Tested flowing bottom-hole pressure, p wf 2 ¼
3.2 Construct IPR of a vertical well in a saturated oil 1,500 psia
reservoir using Vogel’s equation. The following data Tested production rate at p wf 2 ,q 2 ¼ 900 stb=day
are given:
3.6 Determine the IPR for a well at the time when the
Porosity, f ¼ 0:2
Effective horizontal permeability, k ¼ 80 md average reservoir pressure will be 1,500 psig. The fol-
Pay zone thickness, h ¼ 55 ft lowing data are obtained from laboratory tests of well
p
Reservoir pressure, p ¼ 4,500 psia fluid samples:
Bubble point pressure, p b ¼ 4,500 psia
Fluid formation volume factor, B o ¼ 1:1
Fluid viscosity, m o ¼ 1:8cp Reservoir properties Present Future
Total compressibility, c t ¼ 0:000013 psi 1 Average pressure (psig) 2,200 1,500
Drainage area, A ¼ 640 acres (r e ¼ 2,980 ft) Productivity index J (stb/day-psi) 1.25

Wellbore radius, r w ¼ 0:328 ft Oil viscosity (cp) 3.55 3.85
Skin factor, S ¼ 2
Oil formation volume factor (rb/stb) 1.20 1.15
3.3 Construct IPR of a vertical well in an unsaturated oil Relative permeability to oil 0.82 0.65
reservoir using generalized Vogel’s equation. The fol-
lowing data are given:
3.7 Using Fetkovich’s method, plot the IPR curve
Porosity, f ¼ 0:25 for a well in which p i is 3,000 psia and J ¼ 4 10 4
0
o
Effective horizontal permeability, k ¼ 100 md stb=day-psia . Predict the IPRs of the well at well
2
Pay zone thickness, h ¼ 55 ft shut-in static pressures of 2,500 psia, 2,000 psia,
p
Reservoir pressure, p ¼ 5,000 psia 1,500 psia, and 1,000 psia.
Bubble point pressure, p b ¼ 3,000 psia
Fluid formation volume factor, B o ¼ 1:2
Fluid viscosity, m o ¼ 1:8cp