Chilingarian G.V. et al. Surface Operations in Petroleum Production, II
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TABLE
7-1
Typical data
on
steam injection projects
Location
Mount Poso, California
Cat Canyon, California
Duri Field, Sumatra
Kern River, California
South Belridge, California
Pence River, Alberta
Cold Lake, Alberta
Depth Porosity Permeability
Oil
Oil
Primary Average Total Recovery
Cumulative
(ft)
(W)
(mD)
saturation
gravity production
injection oil rate
(W
OIP)
oil/steam
1800 33
2500 31
525 37
705
35
1100 35
1800 28
1500 35
15,000 58
5000 65
6400 62
7600
52
3000 76
1050 17
1500 60
(OAPI)
(W
IOIP)
rate (BOPD) ratio
(BWPD/well) (bbl/bbl)
16 35 2000 13,000 60 0.18
9 12
500 250 43 0.25
22
10 1000 34,000 58 6.10
14 13 600
1490 63 0.17
13 9 600 3200 26 0.28
9
-
1500 3500
50
0.25
10
-
1500 5000 20
0.40
226
TABLE
7-11
Estimated World reserves of heavy crude
oil
and tar sands
in
millions
of
barrels (After
R.F.
Meyer,
Dec.
15,
1982,
personal communication)
Medium crude oil,
20-25
API
Canada
U.S.A.
Central America
South America
Europe
Africa
Middle East
U.S.S.R./Asia
Totals
119
2271
108
8376
154
4197
32,759
660
48,644
-
Heavy crude
oil,
Tar
sands
less than
20
API
69
333,010
2254 2512
331
-
5654 100,012
134
-
89 175
3528
-
97
16
12,756 435,725
-
are millidarcies (mD). The higher the permeability
of
a formation, the greater the
number and width of passageways for steam to flow through. For example,
Pennsylvania oil sands which have very low permeabilities in the range
of
10
md,
are not good candidates for the steam injection process.
A
high permeability is a
prerequisite for the successful application of thermal enhanced oil recovery by the
steam injection technique.
(3)
Average injection rate
It
is
the usual practice to inject as much steam into an injection well as the well
will accept, in order to heat the subsurface strata as rapidly as possible. The
injection rate is normally given in barrels of water equivalent per day (BWPD). The
rate at which a well accepts steam is generally dictated by the permeability, the
formation thickness, the oil saturation, and the pressure
of
the injection steam. The
maximum pressure of the injection steam is largely established by the depth of the
injection well. It is desirable to inject steam at as high a pressure as possible in order
to increase the temperature of the steam, and maximize the driving force for heat
transfer to the oil strata. The maximum steam pressure cannot be greater than the
weight of the overburden at the injection depth; otherwise, the steam pressure will
cause fracturing and eruptions.
(4)
Recovery
The recovery of oil from a given reservoir is measured in terms
of
the percentage
of the original oil in-place (OIP), which has been recovered through primary
production and thermal enhanced oil recovery. The projects listed are on-going, and
the percentage recovery figures shown are as
of
late
1980.
(5)
Cumulative oiE/steam ratio
The cumulative oil/steam ratio column in Table 7-1 indicates the amount of
221
injection steam required to produce a given amount
of
crude oil at each of the listed
fields. At Mount
Poso,
for example, it requires 5.56 barrels of water equivalent to
produce one barrel of crude oil. Stated in different terms, one barrel of oil must be
burned in a steam generator to make the steam required to produce 2.57 barrels of
crude oil through the steam injection technique, giving a net gain of 1.57 barrels of
crude oil. This installation would have to be classed as being at the lower economic
limit for a steam injection project.
The South Belridge, California, installation is somewhat more typical of economi-
cally attractive steam injection projects in that it requires 3.57 barrels of water
equivalent to produce one barrel of crude oil. Converted to different terms, this
installation would burn one barrel of oil in the steam generator to produce
4
barrels
of crude oil through steam injection, thus yielding a net gain of 3 barrels of crude
oil.
These figures are based on oilfield steam generators having a thermal efficiency
of 82% based on the net heating value
of
the fuel. As an average for steam injection
projects, one may assume that out of every three barrels of crude oil produced by
steam injection, one barrel must be burned in the oilfield steam generator to
produce the injection steam. Similarly, it has been established that a cumulative
oil/steam ratio below 0.25 is seldom economically attractive.
Wellbore and formation heat losses
Steam is an efficient medium for heating the subsurface strata and the reservoir
fluids contained therein, because much of the energy available in the steam is in the
form of latent heat which it releases at constant temperature as it condenses upon
contacting the relatively cold subsurface strata. This release
of
large portions
of
the
heat contained in the steam with no change in temperature provides the maximum
driving force for transferring heat to the subsurface strata in the minimum time,
thus accelerating the enhanced recovery of crude oil.
The overall thermal efficiency of a steam injection project as measured by the
total energy expended to produce a barrel of crude oil can be significantly
influenced by the percentage of the heat available in the steam at the outlet of the
steam generator which
is
delivered to the oil-bearing subsurface strata. There are
several areas
of
heat and energy
loss
whch serve to reduce both the temperature of
the steam and the amount of useful heat delivered by the steam to the oil-bearing
strata:
(1)
Friction losses in the aboveground transmission piping and downhole injec-
tion tubing reduce the steam temperature.
(2)
Radiation losses from surface steam transmission piping.
(3) Radiation losses from the downhole injection tubing through the casing to
(4)
Radiation losses from the top and bottom planes of the oil-bearing formation
Each of the above energy and heat losses are individually discussed here.
the subsurface strata.
to the adjacent strata.
228
Friction
loss
effect on steam temperature
The temperature of the steam introduced to the oil-bearing stratum is always
lower than the steam temperature at the outlet of the oilfield steam generator,
because of the friction losses experienced in the intervening piping. The temperature
of saturated steam is a direct function of the pressure as can be determined from
any handbook. Depending on the length
of
the surface steam transmission piping
and the depth of the injection well, the piping friction losses can represent
10-50%
of
the steam pressure developed at the outlet of the steam generator. Thus, if steam
at a pressure of
1500
psia is generated at the outlet
of
the oilfield steam generator
and the pressure is reduced to
1000
psia at the injection point by piping friction
losses, the temperature
of
the steam must have been reduced from
596OF
at the
point
of
generation to
545OF
at the point where it is injected into the oil-bearing
stratum. The loss in steam temperature reduces the driving force for heat transfer
from the steam to the oil-bearing stratum, and increases the length of time which is
required to heat the oil-bearing formation.
In modern steam injection practice, it is conventional to generate 80%-quality
steam for transmission to the injection wells. The reasons for this practice are
discussed at length in the section of Equipment Designs.
This
means that friction
loss
calculations for the surface transmission piping must be based on two-phase
flow, which involves a fairly complex calculation. The friction losses in the surface
steam transmission piping for 85%-quality steam may be approximated from the
Fig.
7-3.
4
W
I-
m
I I I
I:
1.0
I(
10.0
I
Fig.
7-3.
Chart for approximate determination
of
pressure drop
of
85%-quality steam
flowing
in
steel
pipes.
229
Surface radiation losses
The larger steam injection projects generally have extensive surface steam trans-
mission piping systems to transport the steam from a group of oilfield steam
generators to multiple injection wells. There are several sites in California,
U.S.A.,
for example, where the steam is transported over several miles. The surface
transmission piping may or may not be insulated, depending on the climatic
conditions and relative economics of each site. In any event, both friction losses and
radiation losses are experienced in the surface transmission piping, and these losses
serve to reduce both the temperature and the quality of the steam. The radiation
losses from insulated or uninsulated surface steam transmission piping can readily
be determined for any pipe size, climatic condition, and steam temperature by
procedures available in standard handbooks. Typical radiation loss values are given
in Table 7-111.
Wellbore heat losses
Heat losses from the downhole injection tubing may represent a significant
economic factor on a steam injection project, particularly in applications involving
deep wells or in wells in which the steam injection rates are quite low.
A
sharp
reduction in the steam quality between the wellhead and the point where the steam
is actually injected into the oil-bearing stratum is possible as a result of heat losses
TABLE 7-111
Heat loss rates in bare and insulated steel pipe (After Ramey, 1965)
Insulation Conditions Heat loss,
surface area, at inside
temperature of
(Btu/hr-ft
2,
200°F 400°F 600°F
Bare steel pipe
Still air,
0
"
F
Still air,
100
"
F
10-mph wind,
0
"
F
10-mph wind,
100
OF
40-mph wind,
0
"
F
40-mph wind,
100
"
F
540 1500 3120
210 990
2250
1010 2540 4680
440
1710 3500
1620 4120
7440
700 2760 5650
Magnesia pipe
insulation, air
temperature
=
80
OF
Heat
loss,
at inside temperature
of
(Btu/hr-ft
')
200°F 400°F 600°F 800°F
Standard on 3-in. pipe
50
150 270
440
1;
in. on 6-in. pipe 64 186
335 497
Standard on 6-in. pipe 71 232
417 620
1
f
in. on 3-in. pipe 40 115
207 330
3 in. on 3-in. pipe 24 75 135 200
3 in. on 6-in. pipe 40 116 207 322
230
from the downhole injection tubing to the surrounding subsurface rock formation.
This
subject, which is critical in enhanced oil recovery operations, has received
extensive attention in the technical literature. For in-depth coverage
of
the subject,
one should consult Rubinshtein (1959), Ramey (1962, 1965), Avdonin (1964, 1969),
Leutwyler and Bigelow (1964), Leutwyler (1965), Satter (1965), Willhite (1966),
Greer and Shryock (1967), Willhite and Dietrich (1967), Erlougher (1968), Traynor
(1980).
Steam may be injected down the casing, but is is usual practice to inject the
steam through the tubing which is centered in the casing. The annulus between the
casing and the tubing
is
sealed by a high-temperature thermal packer located
slightly above the point where the steam is injected into the oil-bearing stratum. The
purpose of the thermal packer is to stop the backflow of steam through the annulus
to
the atmosphere.
The calculation of heat losses from the steam as it flows downward between the
wellhead and the point where it is injected into the oil-bearing stratum is a complex
process. The injection tubing is heated to the steam temperature and transfers heat
to the casing by radiation, convection, and conduction. The casing, in turn, transfers
heat continuously to the surrounding strata. The result is a continuing flow of heat
from the steam to the strata, which, in turn, reduce the amount of heat available to
be
delivered to the oil-bearing formation. Inasmuch as the heat loss
is
directly
proportional to the length of the injection downhole tubing, the heat loss effect
becomes more critical in the deeper wells. Similarly, inasmuch as the heat loss is
primarily a function of steam temperature rather than steam quantity flowing
through the injection tubing, the percentage
of
heat loss increases inversely with the
rate
of
steam injection in a given well. Thus, for a given steam temperature, the
percentage of heat which is lost to the strata increases as the quantity of injection
steam decreases.
A
simplified approach to the calculation of wellbore heat loss is based on an
assumption that steam temperature over the length of the downhole injection tubing
is
constant. This is not strictly accurate in that the steam temperature is reduced
because of the pressure decrease resulting from the friction loss through the
injection tubing. The simplified approach incorporates calculation
of
conduction
and radiation
of
heat from the injection tubing to the casing,
q,+c,
and conduction
of heat from the casing to the surrounding strata,
qcPs:
and
231
where:
4
k,,
k,,
a
ri,
roc
=
outside radius of casing, ft;
roi
E
=
effective emissivity
of
tubing and casing (about
0.6);
u
T,
T,
T,
T,,
T,,
=
heat loss per unit of injection tubing length;
=
thermal conductivity
of
the annulus fluid, Btu/hr -ft
-
OF;
=
thermal conductivity
of
the earth, Btu/hr -ft
-
OF;
=
thermal diffusivity of the earth, ft2/hr (Table 7-IV);
=
inside radius of casing, ft;
=
outside radius
of
injection tubing, ft;
=
Stefan-Boltzmann constant, 0.1713
X
lo-*;
=
temperature of the steam,
OF;
=
temperature of the casing,
OF;
=
temperature of the earth,
OF;
=
temperature
of
the steam,
"F
absolute; and
=
temperature
of
the casing,
OF
absolute.
The above two equations can be solved for the casing temperature
and the
heat loss per unit
of
injection tubing length,
4.
Once the loss
of
heat per foot of
injection tubing
4
has been established, the total heat
loss
from the injection tubing
can be determined by multiplying
q
by the total length of injecting tubing. From the
total heat
loss
figure, the deterioration in steam quality from the wellhead to the
TABLE
7-IV
Rock thermal properties (After Somerton,
1958)
Density
Specific heat Thermal conductivity
Thermal diffusivity,
(lb/cu ft)
(Btu/lb-
F)
(Btu/hr-ft-
F)
(ft */hr)
Dry
rocks
Sandstone
130
Silty sand
119
Siltstone
120
Shale
145
Limestone
137
Sand (fine)
102
Sand (coarse)
109
Water-saturated rocks
Sandstone
142
Silty sand
132
Silts tone
132
Shale
149
Limestone
149
Sand (fine)
126
Sand (coarse)
130
0.183
0.202
0.204
0.192
0.202
0.183
0.183
0.252
0.288
0.276
0.213
0.266
0.339
0.315
0.507
(0.40)
0.396
0.603
0.983
0.362
0.322
1.592
(1.5)
(1.51)
0.975
2.050
1.590
1.775
0.0213
(0.01 67)
0.0162
0.0216
0.0355
0.0194
0.0161
0.0445
(0.0394)
(0.0414)
0.0307
0.0517
0.0372
0.0433
Values in parentheses are estimated.
232
I
e-
W
0
Y
0
e-
W
W
U
,
+
W
I
a
m
a
m
m
s
e-
w
I
6
8
10
10
STEAM INJECTION RATE,
LB/HR
x
lo3
Fig.
7-4.
Interrelationship among heat
loss
to the formation, steam injection rate, and pressure. (After
Satter,
1965;
courtesy
of
the Society of Petroleum Engineers of AIME.)
point where the steam
is
injected into the oil-bearing stratum can be readily
determined from any steam table (see Farouq Ali,
1966,
and Pacheco and Farouq
Ali,
1972).
The simplified procedure for determining wellbore heat losses described above
has a number
of
limitations, but should prove satisfactory for approximate heat
loss
evaluations. The primary limitation is the assumption of a constant steam tempera-
ture over the full length of the injection tubing. The accuracy of the heat
loss
determination can be increased significantly by breaking up the total length of the
injection tubing into increments, and adjusting the steam temperature in each
increment for the friction loss effect on the temperature experienced in that
increment. Figure
7-4
provides an approximate picture of wellbore heat losses as a
function of steam injection pressure and injection rate.
The interest in applying the steam injection technique to deeper wells plus the
accelerating rise in the cost of fuels has promoted intensive development in means
to reduce wellbore heat losses. The result has been development of reliable insulated
233
LT
5400-
.
3
C
4800-
1
3
4200-
s
6000
=O08
3600-
3000-
2400-
1800-
1200-
600
-
I
0.5
1.0
1.5
2.0
2.5
3.0
WELL
DEPTH,
FT
I
103
Fig.
7-5.
Wellbore heat losses using insulated and uninsulated injection tubing. (After Davis and
Fanaritis,
1982;
courtesy
of
The
Oil
and
Gas
Journal.)
injection tubing, which reduces heat losses and minimizes thermal stresses in the
casing induced
by
high casing temperatures. Figure
7-5
shows a comparison
of
heat
losses
from
insulated and uninsulated tubing over a range
of
well depths (Davis and
Fanaritis,
1982).
Table
7-V
shows comparative heat losses with insulated and
TABLE
7-V
Comparative heat
losses
with insulated and uninsulated tubing in a location
in
Alberta, Canada (2300-ft
deep well, 80%-quality steam at
2000
psig and
635
OF;
600
bbl/D water equivalent injection rate; steam
drive) (after Traynor,
1980)
Injection through Injection through
uninsulated tubing insulated tubing
Heat at wellhead, Btu/hr
9,174,940 9,174,940
Heat at reservoir, Btu/hr
7,217,069 8,945,884
Heat differential in reservoir, Btu/hr
0
1,728,815
Casing temperature,
OF
465
108
Steam quality at reservoir,
'%
32 74
Heat
loss,
X
21.3
2.5
234
I
A.
PRESTRESSED
I
~
COLLAR TUBING CASING
STEEL BUSHING INSULATION
\-
CORDIERITE CENTRALIZER RINGS
Fig.
7-6.
Two different designs of insulated downhole tubing. (After
Davis
and Fanaritis,
1982;
courtesy
of
The
Oil
and
Gas
Journal.)
uninsulated tubing on a specific project. Two typical types
of
insulated downhole
injection tubing, whch are currently in use, are shown in Fig.
7-6.
Heat
losses
to surrounding formations
Every oil-bearing stratum regardless of its thickness, is surrounded by non-oil-
bearing rock with which it is in direct contact. Heat is transmitted by conduction
from the oil-bearing stratum into which steam is being injected to the non-oil-bearing
rock, from both the top and bottom planes
of
contact. Heat lost from the
oil-bearing stratum to the surrounding non-oil-bearing rock is not productive in
increasing the recovery of crude oil in a steam injection project, and thus its impact
must be evaluated as it affects the project economics. Inasmuch as the area
of
the
contact planes between the oil-bearing stratum and the surrounding rocks remains
constant regardless
of
the thickness
of
the oil-bearing formation, it becomes obvious
that the percentage of total injected heat which is lost from the upper and lower
planes
of
the oil-bearing stratum varies inversely with the thickness of the oil-bearing
formation.