1. No category

MINISTRY OF SCIENCE AND TECHNOLOGY
DEPARTMENT OF
TECHNICAL AND VOCATIONAL EDUCATION
Sample Questions & Worked Out Examples
For
PE-05033
ADVANCED PETROLEUM
PRODUCTION ENGINEERING
B.E
Petroleum Engineering
1
Ministry of Science and Technology
Department of Technical and Vocational Education
Petroleum Engineering
Sample Questions for
PE-05033 Advanced Petroleum Production Engineering
(1)
Anew flowing well completed with 2 7/8 in, tubing hung at the top of the
perforations at 5500ft was initially produced on a ¼ in choke, the THP
stabilizing at 400 psig. After a few day's production, the choke size was
increased to ½ in and the THP stabilized at 270 psig. One week later the
choke size was again increased and the well was then gauged at 600 stb/d of
clean oil, GOR 800 scf/stb, THP 140 psig. Assuming a Vogel IPR, estimate
the well's static pressure and its pumped-off potential.
(m)
(2)
A 2000 ft well completed with a 3 ½ in tubing is flowing 600 bbl/day, GLR
1.0mcf / bbl, against a THP of 600 psi. Determine the rate of change. (s)
(3)
A 5000-ft well completed with 2 3/8 in tubing is flowing 200 bbl/day, GLR
1.0 mcf/bbl, against a THP of 200 psi. Determine the rate of change. (c)
(4)
Given data:
Depth
Pwh
PI
Oil allowable
2 ½ in tubing
PR
GOR
=
=
=
=
7000 ft
120psi
1.5(assume constant)
200bpd
=
=
2400 psi (constant)
800 scf / bbl
The water cut is increasing and the flowing GLR is changing accordingly.
A computer solution to this problem is much preferred because working
curves are not available for all water-cuts, however interpolations can be made
to illustrate this change. Reference should be made to all curves for vertical
flow pressure traverse.
(1) Construct a pressure flow rate diagrams.
(2) Draw in the inflow performance curve for a constant PI of 1.5
(3) Construct the vertical flow performance curve for different rates
accounting for the change in GLR.
(4) The rate above which the well will no longer makes its oil allowable is
690 bpd total liquid.
(5) Determine the water percentage at this rate.
(m)
2
(5)
Given data:
Depth
Pwh
PI
Oil allowable
2 ½ in tubing
PR
GOR
= 7500 ft
= 100 psi
= 4 ( assume constant )
= 150 bpd
= 2500 psi (constant)
= 1000 scf / bbl
Find the water-cut at which be the well no longer flows its allowable of 150
bpd oil.
(s)
(6)
Given data:
Depth
Pwh
PI
Oil alloowable
2 in tubing
PR
GOR
= 8000 ft
= 80 psi
= 2 (assume constant)
= 100 bpd
= 2600 psi ( constant )
= 600 scf / bbl
Water starts moving into the well and continuous to increase until the well will no
longer makes its allowable. Find the water-cut at which the well will no longer flow 100
bpd oil. Assume that the GLR varies but GOR remains constant.
(c)
(7)
Given data:
Depth
= 8000 ft
Oil allowable
= 200 bpd
= 2800 psi
PR original
PR is decreasing at a rate of 100 psi per 10,000 bbl of recovery.
PI
= 0.0015 PR
2 ½ in tubing
GOR
s allowable.
Find the GLR, Pwf , qo , and qw , at this cumulative recovery.
(8)
orig
(m)
Given Data:
Depth
= 6500 ft
Oil allowable
= 100 bpd
PR original
= 2200 psi
PR is decreasing at a rate of 200 psi per 10,000 bbl of recovery.
The well starts making water after 20,000 bbl of recovery and the water increases
at (0.75) (previous rate)
3
Plot a pressure flow rate diagram finding that rate at which the well will no longer
produce its allowable. Find the GOR, GLR, Pwf , qo and qw at this cumulative recovery.
(s)
(9)
Correlate the field data of a flowing well and calculate pressure gradient given
Oil production
Gas oil ratio
Tubing Size
Flowing BHP
Average flowing temperature
Gravity of oil
Gravity of gas
Tubing pressure
Depth
No water production.
(10)
= 302 STB / Day.
= 936 SCF / STB.
= 2 ½ in , ID = 2.441 in
= 2530 psia
= 100 °F
= 42.3 ° API
= 0.816
= 860 psia
= 6850 ft
Calculate the point of gas injection and the gas-oil ratio for a well on
continuous-flow gas lift, given:
Depth of well
= 8000 ft
Static BHP
= 3000 psia
Water production
= 400 bbl/day.
Specific gravity of water
= 1.15
Specific gravity of lift gas and seperator gas = 0.60
Bottom-hole temperature
= 200° F
Back pressure at tubing
= 100 psia
Surface temperature
= 70°F
Productivity index
= 1.0 bbl/day/psi
Oil production desired
= 40 bbl/day
Total production
= 440 bbl/day.
Gravity of oil
= 40˚ API at 60˚F (0.825)
Solution Gas Oil Ratio
= 680 scf / stb
Tubing size
= 2 ½ in , 6.5 lb/ft.
(11)
(12)
(13)
(14)
(15)
(16)
(17)
(c)
(m)
Describe the classifications of Compressor systems.
(s)
Explain the how many factors are considered in the design of any system: (c)
Discuss the producing methods involving liquid slugs.
(m)
Explain the intermittent gas lift.
(s)
Describe the plunger lift.
(c)
Describe chamber lift.
(m)
Consideration is being given to closed intermittent gas lift installation on a
well. The installation would use 2 7/8 in tubing hung just above the top
perforations at 5872 ft. The static pressure in the formation is 1120 psig and
the IPR is almost a straight line, The average PI being 0.8 bbl/(day)(psi).
Similar installation in the same field confirm that an average upward slug
velocity of 900 ft / min during the gas. Injection stage is reasonable, and that
4
the fallback to anticipitatrd at that velocity is 3 bbl. The back pressure on the
tubing from the surface facilities is 100 psig and the pressure gradient exerted
by the liquid from the formation is 0.31 psi/ft.
Determine the optimum number of cycles per day and also the sensitivity
of that optimum number to variations in Jw / a and the average upward slug velocity.
Calculate the production rate to be expected on the intermittent gas lift installation.
(s)
(18)
(19)
(20)
(21)
A well is intermitting at 460 bbl/day from 7421 ft cm 3 ½ in tubing (internal
cross-sectional area 0.0325 sqft). The gas injection time per cycle is 20 min. It
is estimated that the static pressure of the producing horizon is 1450 psig and
then the PI is 0.3 bbl/day (psi). Could the production rate from the well be
substantially improved by changing the number of cycles per day?
(c)
A well producing from 14,020 ft is making 120 bbl/day on intermittent gas
lift, 40 cycles/ day, through 2 7/8 in tubing (internal cross-sectional area
0.0325 sqft). The gas injection time per cycle is 20 min. It is estimated that the
static pressure of the producing horizon is 1450 psig and then the PI is 0.3
bbl/day (psi). Could the producing rate from the well be substantially
improved by changing the number of cycles per day?
(m)
Consideration is being given to a closed intermittent gas-lift installation. On a
well. The installation would use 2 7/8 in tubing hung just above the top
perforations at 5872 ft. The static pressure in the formation is 1120 psig and
the IPR is almost a straight line, the average PI being 0,8 bbl/ (day) (psi).
Similar installation in the same field confirm that an average upward slug
velocity of 900 ft/min during the gas injection stage is reasonable, and that the
fallback to be anticipated at that velocity is 3bbl. The back pressure on the
tubing from the surface facilities is 100 psig and the pressure gradient exerted
by the liquid from the formation is 0.31 psi/ft. Determine the volume of gas
that would be needed daily to intermit the well at the optimum number (57) of
aydes per day , Also determine the value of the THP during production of a
slug at the surface.
(s)
Consideration is being given to placing a well an intermittent gas lift. The
well is completed over the interval 11, 032 to 11, 071, ft below tubing a =
0.0318 sq ft in the hale. Initial planning is being carried ant on the basis of a
closed system utilizing the 27/8 in tubing, and an the assumption that the
upward slug velocity during the injection period will be 750 ft/min. Other well
data are as fallows:
Average PI
=
117 bbl/ (day) (psig)
Formation static pressure
=
1570 psig
Pressure gradient exerted by formation liquid 0.29 psig/ft minimum line
pressure in gathering system 150 psig.
Determine the optimum number of cycles per day and calculate the
anticipated production rate, the maximum THP, the volume of injection gas
required per cycle, and the maximum gad injection pressure for assumed vales
of the fallback per cycle of 0,2,4,6,8 and 10 bbl. Use these calculations to
predict portable results.
(c)
5
(22)
(23)
(24)
(25)
(26)
(27)
(28)
(29)
(30)
(31)
(32)
(33)
(34)
(35)
(36)
(37)
What would be the affect to chamber lift installation were made in the well the
installation in during 2000 ft of 4 in tubing (a = 0,0850 sq ft ) rum an 9000 ft
of 27/8 in tubing ? (In this problem it is necessary to assume a value for the
THP during production of the slug; the calculation would suggest 300 psig as
a reasonable figure. The explanation for this point of difference between the
solution to the prod 21 and 22 is that the gas pressured required to move that
slug up the 27/8 on tubing is considerable greater than the needed to lift the
liquid at of 4 in chamber because of the length of the slug un the smaller
tubing.
(m)
A pump is to be set in a well at the working fluid level of 4000 ft. It is desired
to produce 400 bpd of fluid at the surface. If local experience indicates that
pump efficiency is 80% what size pump would you recommend for this well?
(s)
Estimate peak and minimum polished rod loads, counterbalance required, and
peak torque for both mark II and coventional units for the following condition
Pumping depth
=
5900 ft
Desired fluid production
=
150 lipd
Volumetric efficiency
=
80 %
Stroke length
=
64 in
Pumping speed
=
16.5 spm
Pump diameter
=
1 in
Rod number
=
API no.76(1814lb/ ft)
Fluid specific
=
1.0
(c)
A pumping installation consists of 2 in pump set at 7080 ft in 2 in tubing. Oil
warring a speribri gravity of 0.81 if at level of 5800 ft in the casing annulus.
The unit utilizes a rod string consisting of 3/4 in and 7/8 in rods and operates
at 16.8 spm. Pump efficiency is 75% and 55 bpd are being produced.
Determine for a conventional unit
(a)
Peak polished rod load
(b)
Minimum polished rod load
(c)
Counterbalance required
(d)
Peak Torque
(m)
Repeat prob 25 for Mark II unit.
(s)
Explain the factors affecting selection of artificial lift equipment
(c)
Describe the producing characteristics of selectoin of artificial lift equipment.
(m)
Explain fluid properties of selection of artificial lift equipment .
(s)
Describe hole characteristics of selection of artificial lift equipment. (c)
Explain reservoir characteristics of selection of artificial lift equipment (m)
Describe the depletoin drive reservoir .
(s)
Explain the water drive reservoir.
(c)
Describe the gas cap expansion drive.
(m)
Explain long-range recovery plan.
(s)
Describe the surface facilities of the selection of artificial lift equipment.
(c)
Explain the location of the selection of artificial lift equipment.
(m)
6
(38)
(39)
(40)
(41)
(42)
(43)
(44)
(45)
(46)
(47)
(48)
(49)
(50)
Discuss relative economics of the selection of artificial lift epuipment. (s)
Discuss on types of artificial lift.
(c)
Describe advantages of artificial lift method.
(m)
Describe disadvantage of artificial lift method.
(s)
Describe advantages & disadvantages of artificial lift.
(c)
Explain advantages and disadvantages of Gas lift.
(m)
Describe advantages of gas loft.
(s)
Describe disadvantages of gas lift.
(c)
Explain the advantages and disadvantages of hydraulic pumping.
(m)
Describe the disadvantages of hydraulic pumping.
(s)
Explain the advantages of hydraulic pumping.
(c)
Describe the advantages and disadvantages of electrical submersible pump.
(m)
Explain the advantages of electrical submersible pump.
(s)
Ministry of Science and Technology
Department of Technical and Vocational Education
Petroleum Engineering
Worked Out Examples for
PE-05033 Advanced Petroleum Production Engineering
1. Chapter (1) Page. 2,3,4,5. Example 1.1
2. Chapter (1) Example 1.2 and 1.3 Page. (10,11)
3. Chapter (1) Example 1.4 Page. (14)
4. Chapter (1) Example 1.5 Page. (16)
5. Chapter (2) Example 2.1 Page. (28)
6. Chapter (2) Example 2.2 Page. (31)
7. Chapter (3) Example 3.3 Page. (52)
8. Chapter (3) Example 3.4 Page. (53)
9. Chapter (4) Example 4.1 Page. (58)
10. Chapter (4) Example 4.2 Page. (63)