Course:- 28117
Class:- 289033b
HERIOT-WATT UNIVERSITY
DEPARTMENT OF PETROLEUM ENGINEERING
Examination for the Degree of
MEng in Petroleum Engineering
Production Technology 2
Thursday 2X April 200X
09.30 - 11.45
NOTES FOR CANDIDATES
1. This is a Closed Book Examination.
2. 15 minutes reading time is provided from 09.15 - 09.30.
3. Examination Papers will be marked anonymously. See separate instructions for
completion of Script Book front covers and attachment of loose pages. Do not write your
name on any loose pages which are submitted as part of your answer.
4. This Paper consists of 1 Section:-
Attempt 3 numbered Questions from 4
5. Marks for Questions and parts are indicated in brackets
6. This Examination represents 70% of the Class assessment.
7. State clearly any assumptions used and intermediate calculations made in numerical
questions. No marks can be given for an incorrect answer if the method of calculation is
not presented.
1.
(a) Sketch the main components of a 3 phase (gas/oil/water) horizontal separator and briefly
(one sentence) explain the function of each of the main components.
[8]
(b) Indicate how the export of the oil/water/gas flows are controlled and why the outlets are
situated at your indicated locations.
[3]
(c) Stokes Law (below) describes the velocity of separation (v) of one liquid from another
kD 2 (ρd − ρc )
V=
µc
Where D is the droplet size, ρ the density, µ the viscosity and c and d refer to the continuous and
discontinuous phases respectively. An oil/water 2-phase separator has been in use in a field for
many years. The main producing zone (35˚ API, saline formation water) is now depleted and it
is proposed to produce a shallower, subsidiary zone (17˚ API oil, fresh formation water). The
required data are given in Table 1.
You are required to advise management as to whether the existing separator capacity is sufficient
when the subsidiary zone is producing at 1% and 75% water cut.
Table 1.
Fluid properties at Production zone
separator conditions Main Sand Subsidiary Sand
Oil viscosity cp 2.5 40
density/g.cm-3 0.85 0.95
Water viscosity cp 0.9 0.7
density/g.cm-3 1.1 0.99
N.B. The production rate from the subsidiary zone is only 10% of that achieved from the main
zone.
[9]
(d) An assumption has to be made in the above calculations. Indicate its impact on the
conclusion reached in the unfavourable (separator capacity insufficient) case and indicate
two remedial actions that could be taken.
[5]
2.
(a) You are the Production Technologist responsible for completion of a well in a new field.
Briefly list what techniques you would use to help you in the decision as to whether sand
control measures need to be installed.
N.B. A core has been taken across the pay zone.
[8]
(b) This field has been declared marginal and can only be economically developed with
subsea wells. Briefly describe how this will affect your decision:
(i) on the need for the installation of sand control measures and
(ii) type of sand control measures installed.
[5]
(c) The field is developed with an oil well producing through a gravel pack. The (Darcy)
skin due to presence of the gravel pack and the resulting pressure drop (∆Ps) may be
calculated from:
S=
(
96 k / k g L )
2
d n
and
141.2 qBµ
S + 4 2 or
Dq
∆Ps =
KL d n
∆Ps = 0.00539 q S + 4 2
Dq
d n
(see Table 2 for definition of the parameters and numerical values)
Calculate the (Darcy) skin value (S) and the resulting pressure drop for a perforation density of 4
shots/ft.
[4]
This is the target, allowable pressure drop in the well.
(d) Well testing found that the turbulent (non-Darcy) resulted in an unacceptably high
pressure drop of 374 psi. You are required to advise management as to whether the next
well should be completed with:
Case Cost Shot Density Diameter
A Low 12 shots/ft 0.5 in
B High 4 shots/ft 1.0 in
and whether it will meet the target, allowable pressure drop.
[5]
(e) Briefly comment on which case you would have expected to give the better inflow, and
why.
[3]
Table 2
Well Production (q) 2500 STB/D
Total Production Height (h) 23 ft
Reservoir Permeability (k) 578 mD
Oil Viscosity (µo) 0.310 cp
Formation Volume Factor (Bo) 1.636 bbl/STB
20-40 Mesh Gravel Permeability 120,000 mD
Perforation Penetration (L) 6 in
Perforation Diameter (d) 0.5 in
Perforation Density (n) 4 shots/ft
Non-Darcy (turbulance factor) (D) 0.01
3.
(a) List up to 6 key features for both Rod Pumps and Gas Lift that form the basis of the fol
lowing statement:
“Worldwide, 85% of Artificial Lift equipment installed is rod pumps. This is mainly in strip
per wells while gas lift is the most popular artificial lift technique for higher rate wells”.
[6]
(b) Most gas lift fields have insufficient gas to lift all the wells at their (technical) maximum
production. Briefly describe the process of optimal allocation of available lift gas;
mentioning the key economic parameters involved.
[6]
(c) Design a gas lift installation for the following conditions:
Tubing 3.958 in
Required Production Rate 3000 STB/day
Oil Cut 100%
Gas Oil Ratio 100scf/bbl
Gas Specific Gravity 0.65
Average Flowing Temperature 150˚F
Reservoir Productivity Index 4 bpd/psi
Reservoir Depth 10,000 ft
Reservoir Pressure 3400 psi
Lift Gas Injection Gradient 20 psi/1000 ft
Minimum flowing tubing head pressure to
transfer fluids to facility 250 psi
Dead Oil Density 35˚ API or 0.368 psi/ft
Gas Oil Ratio 100 scf/bbl
Brine Density 0.44 psi/ft
Lift Gas Injection Rate 3,000,000 scf/d
A pressure traverse curve is provided as Figure 1.
Tubing size, in. : 3.958
Liquid rate, STBL/D : 3000
Water fraction : 0
Gas gravity : 0.65
Oil API gravity : 35
Water specific gravity : 1.07
Average flowing temp, F. : 150
Assume that the well is closed in with dead oil in the tubing and brine in the casing/tubing
annulus.
(i) does this well require artificial lift to produce?
[2]
(ii) what depth should the gas lift valve be installed in a single valve lift installation in order
to achieve the required production?
[6]
HINT: Note that the relevant portions of the pressure traverse curve can be approximated by
straight lines.
(iii) what is the minimum surface gas injection pressure to kick the well off in the
configuration described?
[4]
(iv) how does this change if dead crude oil was present in the casing/tubing annulus instead
of brine?
[1]
4.
(a) Briefly contrast the generalised selection criteria for matrix acidising and fracturing
treatments when considering carrying out a stimulation treatment on a well.
[5]
(b) List 2 sources of formation damage encountered during drilling and completion
operations and 3 damage sources during production operations. Briefly indicate how the
fluid selection for a (matrix) removal treatment will be influenced by the damage source
(examples may clarify your answer).
[6]
(c) A well completed on 40 acre spacing (re = 745 ft) has a damaged region extending 1 ft
beyond the wellbore (rw = 0.328 ft).
The Hawkins formula may be used to calculate the skin due to formation damage:
k r
Sd = o − 1 d
kd rw
while the productivity ratio (Ji/Jd) of the well with and without the above formation damage is
given by:
re
Ji In rw + S
=
In e r
Jd r
w
Use the above to illustrate the statement:
{“Formation Damage reduces well productivity greatly while the stimulation effect of
increasing the near wellbore permeability above the initial value has limited effect”.}
HINT : estimate the relative well productivity with 95%, 75%, 50% formation damage and 10
times increase in near wellbore formation permeability.
[6]
(d) Your service company has designed the following fracturing treatments:
Wellbore radius (rw): 0.328 ft
Reservoir height: 100 ft; bounded by competent shales
Reservoir Permeability: 0.1 mD
Proppant available: 300,000 lb
Design Fracture Conductivity (kf*w): treatment A
- 1500 mD.ft at 4 lb/ft2 proppant loading
treatment B
- 850 mD.ft at 2 lb/ft2 proppant loading
(i) Use the accompanying graph (Figure 2) from Cinco-Ley and Samiengo to advise
management as to whether treatment A or B will give the highest well productivities.
[6]
(ii) Why would you expect one of these treatments to be preferred?
[2]
End of Paper
