Note: Descriptions are shown in the official language in which they were submitted.
~2~84~2
K 8693 III
IN-SITU STEAM DRIVE OIL RECOVERY PROCESS
This invention relates to recovering oil frcm a subterranean
oil reservoir by means of a conductively heated in-situ steam drive
process. More particularly, the invention relates to treating a
subterranean oil reservoir which is relatively porous and contains
significant proportions of both oil and water but is so impermeable
as to be productive of substantially no fluid in response to
injections of drive fluids such as water, steam, hot gas, or oil
miscible solvents.
Such a reservoir is typified by the Diatomite/Brown Shale
o formations in the Belridge Field (USA). Those formations are
characterized by depths of more than 60 m, thicknesses of about
300 m, a porosity of about 50%, an oil saturation of about 40 per
cent, an oil API gravity of about 30 degrees, a water saturation of
about 60 per cent but a permeability of less than about
1 millidarcy, in spite of the presence of natural fractures within
the formations. m ose formations have been found to yield only a
small percentage of their oil content, such as 5 per cent or less,
in primary production processes. And, they have been substantially
non-responsive to conventional types of secondary or tertiary
recovery processes. The production problems are typified by
publications such as SPE Paper 10773, presented ir. San Francisco in
March, 1982, on "Reasons for Production Decline in the Diatomite
Belridge Oil Field: A Rock Mechanics View", relating to a study
undertaken to explain the rapid decline in oil production. SPE
Paper 10966 presented in New Orleans in September, 1982, on
"Fracturing Results in Diatamaceous Earth Formations South Belridge
Field California" also discusses those production declines. It
states that calculated production curves representative of the
ranges of the conditions encountered indicate cumulative oil
recoveries of only from about 1-14% of the original oil in place.
A conductive heat drive for producing oil from a subterranean
~Z484'~2
-- 2 --
oil shale was invented in Sweden by F. Ljungstroem. That process
(which was invented in the 1940s and commercially used on a small
scale in the 1950s) is described in Swedish patents Nos. 121,737;
123,136; 123,137; 123,138; 125,712 and 126,674, in United States
patent No. 2,732,195 and in journal articles such as: "Underground
Shale Oil Pyrolysis According to the Ljungstroem Method", IV~
Volume 24 (1953) No. 3, pages 118 to 123, and "Net Energy
Recoveries For The In Situ Dielectric Heating of Oil Shale", Oil
Shale Symposium Proceedings 11, page 311 to 330 (1978). In that
process, heat injection wells and fluid producing wells were
completed within a permeable near-surface oil shale formation with
less than a three metre separation between the boreholes. The heat
injection wells were equipped with electrical or other heating
elements which were surrounded by a mess of material (such as sand
or cement) arranged to transmit heat into the oil shale while
preventing any inflowing or outflowing of fluid. In the oil shale
for which the process was designed and tested, a continuous
inflowing of ground water required a continuous pumping-out of
water to avoid an unnecessary wasting of energy in evaporating that
water.
US patent No. 3,113,623 describes means for heating
subterranean earth formations to facilitate hydrocarbon recovery by
using a flow reversal type of burner in which the fuel is inflowed
through a gas permeable tubing in order to cause ccmbustion to take
place throughout an elongated interval of subterranean earth
formation.
With respect to substantially cc~pletely impermeable,
relatively deep and relatively thick, potentially oil-productive
deposits such as tar sands or oil shale deposits, such as those in
the Piceance Basin in the United States, the possibility of
utilizing a conductive heating process for producing oil would
Æ ely be - according to prior teachings and beliefs - economically
unfeasible. For example, in the above-identified Oil Shale
Symposium the Ljungstroem process is characterized as a process
35 which "successfully recovered shale oil by embedding tubular
lZ48442
-- 3 --
electrical heating elements within high-grade shale deposits. This
method relied on ordinary thermal diffusion for shale heating,
which, of course, requires large temperature gradients. Thus,
heating was very non-uniform; months were required to fully retort
small room~size blocks of shale. Also, mNch heat energy was wasted
in underheating the shale regions beyond the periphery of the
retorting zone and overheating the shale closest to the heat
source. m e latter prablem is especially important in the case of
Western shales, since thermal energy in overheated zones, cannot be
fully recovered by diffusion due to endothermic reactions which
take place above about 600 C (page 313).
In substantially impermeable types of subterranean formations,
the creating and maintaining of a permeable zone through which the
heated oil or pyrolysis products can be flowed has been found to be
a severe problem. In US patent No. 3,468,376, it is stated (in
Cols. 1 and 2) that "there are two mechanisms involved in the
transport of heat through the oil shale. Heat is transferred
through the solid mass of oil shale by conduction. m e heat is also
transferred by convection through the solid mass of oil shale. The
transfer of heat by conduction is a relatively slow process. The
average thermal conductivity and average thermal diffusivity of oil
shale are about those of a firebrick. m e matrix of solid oil shale
has an extremely lcw permeability much like unglazed porcelain. As
a result, the convective transfer of heat is limited to heating by
fluid flows obtained in open channels which traverse the oil shale.
m ese flow channels may be natural and artificially induced
fractures. ... On heating, a layer of pyrolyzed oil shale builds
adjacent the channel. miS layer is an inorganic mineral matrix
which contains varying degrees of carbon. m e layer is an ever-
e~panding barrier to heat flow fram the heating fluid in the
channel". m e patent is directed to process for circulating heated
oil shale-pyrolyzing fluid thraugh a flow channel while adding
abrasive particles to the circulating fluid to erode the layer of
pyrolyzed oil shale being formed adjacent to the channel.
US patent No. 3,284,281 says (Col. 1, lines 3-21), "The production
lZ~ 2
- 4 - 63293-2652
of oil from oil shale, by heating the shale by various means such
as ... an electrical resistance heater ... has been attempted with
little success ... Fracturing of the shale oil prior to the
application of heat thereto by in situ combustion or other means
has been practised with little success because the shale swells
upon heating with consequent partial or complete closure of the
fracture." The patent describes a process of sequentially heating
tand thus swelling) the oil shale, then injecting fluid to
hydraulically fracture the swollen shale, then repeating those
steps until a heat-stable fracture has been propagated into a
production well. US patent No. 3,455,391 discloses that in a
subterranean earth formation in which hydraulically induced
fractures tend to be vertical fractures, hot fluids can be flowed
through the vertical fracture to thermally expand the rocks and
close the fractures so that fluid can be injected at a pressure
sufficient to form horizontal fractures.
The present invention aims to provide an improved method
for heating a highly impermeable subterranean reservoir in such a
manner that oil is subsequently produced from the reservoir.
According to the invention at least two wells are completed into a
treatment interval having a thickness of at least about 30 m with-
in an oil and water-containing zone of a reservoir which is both
undesirably impermeable and non-productive in response to injec-
tions of oil-displacing fluids. The invention provides a process
for heating a subterranean oil and water-containing reservoir
formation, comprising:
~Z~4~Z
- 5 - 63293-26S2
completing at least one each of heat-injecting and fluid-
producing wells into a treatment interval of said formation which
is at least about 30 m thick, contains both oil and water, and is
both undesirably impermeable and non-productive in response to
injections of oil recovery fluids;
arranging said wells to have boreholes which, substantially
throughout the treatment interval, are substantially parallel and
are separated by substantially equal distances of at least about
6 m;
in each heat-injecting well, substantially throughout the
treatment interval, sealing the face of the reservoir formation
with a solid material which is relatively heat-conductive and
substantially fluid impermeable;
in each fluid-producing well, substantially throughout the
treatment interval, establishing fluid communication between the
wellbore and the reservoir formation and arranging the well for
producing fluid from the reservoir formation; and
heating the interior of each heat-injecting well, at least
substantially throughout the treatment interval, at a rate or
rates capable of (a) increasing the temperature within the bore-
hole interior to at least about 600C and (b) maintaining a
borehole interior temperature of at least about 600C without
causing it to become high enough to thermally damage equipment
within the borehole while heat is being transmitted away from the
borehole at a rate not significantly faster than that permitted by
the thermal conductivity of the reservoir formation.
The invention will now be explained in more detail with
~Z~34~2
- 5a - 63293-2652
reference to the accompanying drawings, in which:
Figure 1 is a schematic illustration of the temperature
distribution around the heat injector at a typical stage of the
present process.
Figure 2 similarly illustrates such temperature distri-
butions at different stages of the process, the process time t
being expressed in years.
Figure 3 is a plot of oil production rate P (in barrels
per day) with time t (in years) for each heat injection well.
Figure 4 is a plot of process time t (in years) as a
function of well spacing Dw (in metres).
Figure S is a plot of the heat requirement (kJ/barrel
oil) as a function of the process versus time t (in years).
Figures 6 and 7 show plots of oil recovery with time for
simulated thermal conduction processes in reservoir intervals
containing layers of differing permeability.
The present invention is, at least in part, premised on
a discovery that when the presently specified type of reservoir is
treated as presently specified, the process functions as though it
involves a mechanism such as the following.
The injected heat penetrates the formation by conduction
only. However, when the formation temperature rises to say 250-
300~C both water and hydrocarbon vapour are formed and, due to
expansion
~2~8442
of these fluids high pressures are generated. Under the influence
of the generated pressure gradients the fluids flow toward the
production wells, either at the slow rate permitted by the low
native permeability or otherwise through fractures which are
generated or extended into interconnections when the pore pressure
approaches overburden pressure.
When the steam and the hydrocarbon vapour move toward the
production wells they condense in cooler parts of the formation and
the release of latent heat preheats the formation to a "steam"
]O temperature about equalling the temperature of wet steam at the
overburden pressure. In this manner some heat is transported by
convection, thus speeding up the process over what w~uld have been
the case if all of the heat were transmitted by conduction.
Such a generating, pressurizing and displacing of steam and
hydrocarbon vapour through portions of the oil-containing reservoir
amounts to an in situ generated steam drive. m e drive has many
features of the so-called "steam distillation drive" described in
"Laboratory Studies of Oil Recovery by Steam Injection", AIME
Transactions, July, page 681, by B.T. Willman, V.V. Valleroy,
G.W. Runberg, A.J. Cornelius and L.W. Powers (19613. As such, many
of the phenomena observed in the steam distillation drive can be
expected to occur also in the present process, particularly with
respect to the mixing of the hydrocarbon condensate with the virgin
oil in the cooler part of the formation. This hydrocarbon
condensate is more volatile and less viscous than the virgin oil.
When the evaporation front reaches a place where virgin oil has
previously been diluted with hydrocarbon condensate, the resulting
pres Æ ized steam distillation of the diluted oil causes a larger
fraction of the oil to vaporize than when virgin oil is heated to
the same temperature and pres Æ e. This mechanism may increase the
displacement efficiency of the in-situ generated steam drive aspect
of the present process above what could be expected from simple
steam distillation of the virgin crude.
In addition, Applicants have now discovered that in certain
situations it is advantageous to empïoy the following procedures. A
~2~344Z
-- 7 --
preferred way of forming a fluid impermeable barrier between the
reservoir and the portion of the borehole in which the heater is
located is to dispose the heater within a casing or tubing string
which is closed at the bottom and is surrounded by a heat stable
and heat conductive material such as cement. A particularly
suitable rate of generating heat within the heat-injecting wells is
about 1200 to 2400 kJ per metre, per hour, or when heating
electrically, operating an electrical resistance heater at about
330 to 660 watts per metre. Examples of generally suitable rates
are inclusive of 264 to 726 watts per metre or the equivalent rate
~o in kJ. In a reservoir formation (such as the Diatamite/Brown Shale
formation) which has a tendency to undergo ccmpaction and
subsidence around a borehole in which the fluid pressure is
relatively low, the fluid pressure in the fluid-producing wells
should be kept high enough to prevent the compaction. In such
situations, the heating is preferably continued in the
heat-injecting wells until fluid is displaced into at least one
fluid-producing well. The outflowing of fluid from each
fluid-producing well into which fluid is displaced is preferably
restricted to the extent necessary to increase the fluid pressure
within the well by an amount sufficient to prevent significant
compaction of the adjacent formation. In general, such an increase
in the borehole fluid pressure should result in an increase in
reservoir fluid pressure of about 7 to 14 bar above the natural
fluid pressure in the adjacent earth formations. At the
heat-injecting wells the gas pressure developed (steam, methane,
etc.) keeps the pore pressure high and prevents compaction.
Compaction may w cur in Diatomite when the effective pressure
exceeds about 35 bar, independent of temperature, e.g., when the
overburden pressure minus the fluid pressure within the reservoir,0 i.e. the effective stress, amounts to about 35 bar or moreO
ffl us, although the present invention is not dependent upon any
particular mechanism, it functions as though at least a significant
aspect of it consists of a steam distillation drive where the steam
is generated in-situ by heat flowing by conduction from ve~y hot
241 344Z
injection wells.
Figure 1 illustrates schematically the temperature
distribution in the reservoir form~tion around a heat injector at a
typical stage of the present process. It will be assumed that the
heat flows radially so that the formation temperature is a function
only of the distance r to the centre of the heat injector.
In Zone I of Figure 1 located between the well bore radius
(rw) and the evaporation front Irb) all the water has evaporated.
For all practical purposes heat flow is by conduction only. Heat
conduction flows with radial symmetry have in common that over a
surprisingly large region the temperature varies linearly with the
logarithm of r. m is is equivalent to saying that in zone I the
temperature distribution can be accurately described by the steady
state solution of a differential equation.
The pore volume in Zone I contains a small amount of heavy
hydrocarbon residue in liquid or solid form. miS residue forms a
relatively small fraction of the original oil in place and consists
of the heavy components of the crude oil which were not vaporized
by steam distillation. At the prevailing temperatures in Zone I
(e.g., 300-800 C) these hydrocarbons are subject to cracking and
will yield coke and light hydrocarbon gases, which gases will
displace most of the steam initially present. For this reason we
shall assume that in Zone I the pore space which is not occupied by
the heavy hydrocarbons is filled with methane. In other words, no
water is present in any form in Zone I.
In Zone II of Figure 1 located between the evaporation front
(rb) and the condensation front (rf) the temperature has been
assumed to be constant. m is zone is the equivalent of the steam
zone in a conventional steam drive. m e value of the pressure in
Zone II will be assumed to be equal to overburden pressure and the
temperature equal to steam temperature at this pressure. The
rationale behind this assumption is that the permeability of the
Diatcmite~Brown Shale formations is so low in may places that the
pressure may have to rise to fracturing pressure in order to
provide a flow path for the water and hydrocarbon vapours.
~Z~84~Z
In the present process, as in a steam drive, most of the oil
displacement, including steam distillation of oil, can be expected
to occur near the condensation front (rf). m erefore, we shall
assume that the pore space in Zone II is filled with water and
steam at a saturation SwI corresponding to the initial water
saturation, and contains oil at saturation SOII.
In Zone III (located beyond the condensation front (rf) the
pore volume contains the reservoir water and oil at substantially
their initial temperature and saturation.
As mentioned before, contrary to most oil displacement
processes, the vetical sweep efficiency in the present process is
not determuned by the properties of the formation but by the
properties of the heater (at least in first order of
approximation). Ideally, the heat injection rate would be
substantially constant fram top to bottam of the heater, so that
the injection profile would be substantially uniform. ~here the
heater is electric, the heat injected per unit thickness of
formation is qI-i2v/A, where i is the electric current through the
heater, A is its cross sectional area and v the electric
resistivity of the heating wire.
In second order approximation the electric resistivity of a
heating wire increases with temperature. A section of heating wire
opposite a stratum having a lower heat conductivity will became
hotter and therefore more resistive than the section opposite a
layer having a higher heat conductivity. m erefore, paradoxically,
samewhat more heat will be injected into a layer with a lower heat
conductivity.
During the early part of the present process heat will flow
radially outward away from the injectors in a pattern of wells.
This situation may be maintained until the leading edges of two
adjacent hot zones begin to overlap. From then on the temperature
at the point midway between two adjacent injectors will rise faster
(because the midpoint receives heat fram two directions) than at a
point at the same distance fram the heat injector but in the
direction of the production well. We, therefore, have another
: ~48442
-- 10 --
paradoxical situation that the isotherms after first being circular
around the injection wells and growing radially outward, will tend
subsequently to cusp toward each other, thus rapidly heating the
area midway between adjacent heat injectors. This is exactly the
spot which is normally bypassed in oil displacement processes,
causing a reduced sweep efficiency.
In the present process, on the contrary, we can expect very
high horizontal sweep efficiencies, since the oil is displaced by
the thermal gradient and that gradient is selectively directed to
surround and be directed inward toward a production well.
We have assumed before that, in the present process, as in
st steam drives, oil displacement takes place at the steam
condensation front (rf). Consistent with that model, the cumulative
oil production will be proportional to the size of the hot zone.
Since during the early part of the process the heat injection rate
will be higher (assuming constant temperature of the heat
injector), the growth rate of the heated part of the reservoir will
also be higher and therefore the oil production rate larger. Later
on the heat injection rate will decline and so will the oil
production rate.
At the initiation of the present process most of the reservoir
formation will be closed to original oil and water saturation. In
the absence of gas this would mean that oil which is displaced from
the hot zone into the cooler part of the reservoir cannot
significantly increase the initial oil saturation. Therefore, we
can expect that the liquids which are displaced from the hot zone
will quickly cause a production of oil by the production wells, at
least in those layers containing little gas. For example, in a
Diatomite/Brown Shale formation in the Belridge Field at a depth of
about 360 m, when the interior of the heat injecting well is
maintained at a tenperature of about 500 to 700 C and the well
spacing is about 15 m, fluid will be displaced into the production
well within about two years.
Both the oil production rate and the cumulative oil production
are strongly affected by the amount of oil remaining after the
~Z484~;2
passage of Zone II. Preliminary ex~eriments have indicated that
about 70% by weight of a virgin oil such as the Belridge diatomite
oil, is steam distillable. If, however, hydrocarbon condensate
mixes with the original oil (and displaces part of it), a larger
fraction of the mixture will evaporate and more than 70% of the oil
may be recoverable. In the numerical example discussed later,
however, we have assumed only 60% recovery.
A factor which could negatively affect the cumulative oil
production is the geometry of the wells. The well spacing will have
to be exceptionally dense in order to heat up the formation to
process temperature in a reasonably short period of time. Preferred
well distances may be as snall as 20 m. It is obvious that the
boreholes of these wells should be nearly vertical, or at least
substantially parallel, at least within the treatment intexval
within the reservoir, and that deviations from vertical or parallel
of more than a metre could seriously affect the horizontal sweep
efficiency and thus the cumulative oil recovery.
Heat requirement is defined as the amount of heat injected per
b æ rel of oil produced. From the economic point of view this
parameter is of prime importance. Where electric resistance heating
is used, the heat is expensive and the cost of electricity per
barrel of oil produced will be significant. m e presently described
model is somewhat optimistic in terms of process heat requirements.
miS is due to the fact that heat conduction ahead (dcwnstream) of
the condensation front has been neglected. In a steam drive using
injected steam a similar assumption would be more accurate because
the speed of propagation of the steam front is much higher. In the
present process all fronts move very slowly and significant amounts
of heat will move ahead of the condensation front. Later we shall
make an estimate of the size of this error. Heat losses to cap and
base rock have also been neglected; but, this amount of heat loss
is small compared to that lost downstream of the condensation
front.
Where electric heating is used, the greater the electric
current in the heating wire, the higher will be the heat injection
~ z484 4
- 12 -
rate. m e temperature of the heating wire, however, will be higher
also. At too high a temperature the heating wire would melt and a
heat injector would be lost.
It is possible to install electric heaters that can operate at
S temperatures as high as 1200 C. We propose, however, to keep the
maximum temperature of the heating wire below about 900 DC in order
to prevent injector failure requiring a redrilling operation. In
general, the rate of heating is adjusted to the extent required to
maintaim a borehole interior temperature at the selected value
~o without causing it to become high enough to damage well equipment
while the injected heat is being transmitted away from the well at
a rate not significantly faster than that permitted by the heat
oonductivity of the reservoir formation. Such a rate of heating can
advantageously be provided by arranging electrical resistance
heating elements within a closed bottomed casing so that the
pattern of the heater resistances along the interval to be heated
is correlated with the pattern of heat conductivity in the earth
formations adjacent to that interval and operating such heating
elements at an average rate of about 330 to 660 watts per metre of
distance along the interval.
m e following hypothetical examples provide calculations of
the more significant process variables, evaluated for a set of
specific process parameters more or less representative of the
Diatomite/Brown Shale formations in the Belridge Field. m e calcu-
lations evaluate an "average" case characterized by the parametervalues given in Table I.
~Z~8442
- 13 -
TABLE I
P~OESS PARAME~S
Project Area 4.05x10 m
h Formation thickness 335 m
Cg Specific heat of gas in Zone I 0.6 cal/gram C
CT Specific heat of rock minerals 0.2 cal/gram C
CO Specific heat of non-gaseous hydrocarbon 0.4 cal/gram C
in Zone I
CoI Specific heat of non-gaseous hydrocarbon 0.4 cal/gram C
in Zone II
Cw Specific heat of water in Zone II 1.0 cal/gram ~C
Hs Heat content of 1 gram of steam 640~ cal/gram
r~ Radius of heat injector 10 cm
S Hydrocarbon gas saturation in Zone I 0.9
SO Saturation of non-gaseous hydrocarbon 0.1
in Zone I
SoI Saturation of non-gaseous hydrocarbon 0.145
in Zone II
Soi Initial oil saturation 0.36
S Steam saturation in Zone II 0.255
Sw Water saturation in Zone II 0.6
To Original reservoir temperature 40 C
Ts Steam temperature 300 C
Tw Temperature of heat injector 800 C
Porosity 0-55
Coefficient of temperature dependence of 3x10 4/oC
heat conductivity of formation
Value of ~ at 0 C 10 3cal/second
cm C
pI Density of hydrocarbon gas in Zone I 0.04 gram/cm3
T Density of rock minerals 2.5 gram/cm3
pO Density of non-gaseous hydrocarbon in 1.0 gram/cm
Zone I
~,Z4~344Z
IABLE I - (Continued)
pII Density of non-gaseous hydrocarbon in 0.9 gramlom
Zone II
p Density of steam 0.04 granlom3
p~I Density of water in Zone II 0~7 gram~om3
` ~z~3442
Figure 2 illustrates various temperature distributions around
a heat injector as determined for different values of rb
corresponding locations of the condensation fronts (identified by
the respectlve dashed and solid lines, as shcwn on Figure 1). A
striking feature shown by Figure 2 is that only a relatively small
fraction of the formation is heated to very high temperatures. For
instance, the 500 C isotherm doe s not move more than about 3 m
away from the heat injector by the time the evaporation front is
15 m away from the heat injector. Furthermore, Figure 2 illustrates
that the size of the steam zone (Zone II, as shcwn on Figure I)
remains rather small. This is especially important in view of the
fact that we have ignored the heat content of the formation down-
stream of the condensation front. This heat, flawing by conduction
ahead of the steam front, would have to be supplied by reducing the
size of the steam zone even re. We may therefore conclude that
only a small fraction of the formation is actually at steam
temperature. Most of the formation is either hotter (and dry) or
cooler than steam temperature.
Figure 3 shaws the oil production rate P (barrels per day). It
should be noted here that the "oil production" amounts to the oil
displa oe d from the neighbourhood of a heat injector. Since high
sweep efficiencies can be expected in the present process, most of
the displaced oil will be produced. In the case of a five-spot well
pattern there is one producer per injector and therefore Figure 3
may relatively accurately describe the production of oil per
producer. This is especially so since little interference between
injection wells will take place until most of the oil (80%) has
been produced.
In the case of a seven-spot pattern the hot zones of neigh-
bouring heat injectors will start overlapping significantly when
about 60% of the oil has been produced. On the other hand, the
seven-spot pattern contains two heat injectors for every production
well and therefore the initial oil production rate per producer
will be twice as high as in the case of the five-spot pattern. When
the hot zones of adjacent injectors start o~erlapping both heat
- ~Z~8~z
- 16 -
injection rate and oil production rate should start declining
faster than calculated by a radial model. Overall, however, the
initial higher production rate in the case of a seven-spot pattern
should outweigh the later, re rapid decline. So, especially since
heat injectors can be expected to require less expensive well
equipment than production wells, the seven-spot pattern should be
preferable to the five-~Fot pattern.
Figure 4 illustrates the same point by showing that the
process time t (in years) is calculated to be appreciably shorter
for the seven-spot (second curve) than for the five-spot (first
curve), using the same well distance Dw. Furthermore, this figure
shows that well distan oe s Dw of about 20-21 m are required to
ensure that the process lifetime will be in the order of
20-30 years.
Figure 5 illustrates the heat requirements of the process.
Except for early times about 460,000 kJ are injected for every
barrel of oil (bbl) produced. The calculated value of the heat
requirements is optimistic, since heat conduction dcwnstream of the
condensation front has been neglected.
As a consequence of our model, all fluids (oil and water) are
assumed to be produced at original reservoir temperature. In
reality, due to the conductive preheating downstream of the steam
front, after a while the produced fluids will gradually heat up
until they reach steam temperature (at which time the process will
be concluded). Since heat conduction is a slow process, the fluids
will be produced at original reservoir temperature for the first
several years of the duration of the process. As a matter of fact,
it can be shown that at least 25% of the fluids will be produced
cold.
For a conservative estimate of the heat requirements we shall
assume that 25% of the produced fluids will have a temperature
equal to the original formation temperature, but that the remaining
75% of the fluids is produced at steam temperature. This very
conservative assumption raises for our example case the heat
requirement from 460,000 kJ/bbl to 760,000 kJ/bbl. The true value
8~4Z
- 17 -
(accepting the validity of the other assumptions) should be in
between these two numbers and, until we have develaped a more
accurate model, a value of about 600,000 XJ/bbl will be considered
reasonable.
So far we have presented all results in terms of performance
per individual well, or per single pattern. In these terms both
injection and production rates appear to be of small magnitude.
Assuming a well density of 10-12 wells per 4000 m2, we can expect
to inject electric heat at the rate of akout 730 Megawatts and
produce oil at an average rate of 100,000 barrels per day for a
period of 27 years, yieldin~ a cumulative production of one billion
barrels of oil.
m e reservoir to be treated can comprise substantially any
subterranean oil reservoir having a relatively thick oil-containing
layer which is both significantly porous and contains significant
proportions of oil and water but is so impermeable as to be
undesirably unproductive of fluid in response to injections of
conventianal oil recovery fluids. Such a formation preferably has a
product of porosity times oil saturation equalling at least
about .15. m e oil preferably has an API gravity of at least about
10 degrees and the water saturation is preferably at least about
30~. m e invention is particularly advantageous for prcduciny oil
fram reservoirs having a permeability of less than akout 10 milli-
darcys. Additional examples of other reservoirs with similar
characteristics include other diatamite formations in California
(USA) and elsewhere and hydrocarbon-containing chalk formations,
and the like.
m e heat injection wells used in the present process can
camprise substantially any cased or uncased boreholes which la)
extend at least substantially throughout a treatment interval of at
least about 30 m of a subterranean earth formation of the
above-specified type (b) are arranged in a pattern of wells having
boreholes which are substantially parallel throughout the treatment
interval and are separated fram adjacent wells by distances of fram
about 6 to 24 m and (c) contain sheaths or barriers of solid
~L2~84~2
- 18 -
materials which are heat-resitant, heat-conductive and substan-
tially impermeable to fluid, arranged to prevent the flow of fluid
between the interior of the borehole and the exposed faces of the
reservoir formation and/or fractures in fluid communication with
the borehole. As will be apparent to those skilled in the art,
temperature fluctuations are generally tolerable in such a heating
process, using either electrical resistance or combustion heating.
The rate need only be an average rate along the interval being
heated and is not seriously affected by fluctuations such as
temporary shutdcwns, pressure surges, or the like.
The fluid production wells used in the present invention can
be substantially any wells in the above-specified pattern and
arrangement which are adjacent to at least one heat injection well
and which are in fluid ccmmunication with the reservoir formation
at least substantially throughout the treatment interval and are
arranged for producing fluid while maintaining a borehole fluid
pressure which is lower than the reservoir fracturing pressure.
The means for heating the interior of the heat injecting well
can comprise substantially any borehole heating device capable of
increasing and m~intaining the borehole interior temperatures by
the above-specified amLunts. Such heating devices can be electrical
or gas-fired units, with an electrical unit being preferred. The
heating elements are preferably arranged for relatively easy
retrieval within a closed-bottom casing which is sealed to a
heat-conductive, impermeable sheath which contacts the reservoir
formation. The heating means is preferably arranged for both
relatively quickly establishing a temperature of at least about
600 C (preferably 800 C) and for maintaining a temperature of
less than 1000 C (preferably 900 C) for long periods while heat
is being conducted away from the borehole interior at a rate not
significantly faster than that permitted by the heat conductivity
of the reservoir formation.
The heat-stable, heat-conductive and fluid-impermeable
material which forms a barrier between the reservoir formation and
the heater is preferably a steel tubing surrounded by heat
~Z~84~Z
-- 19 --
conductive material in contact with the reservoir formation and/or
fractures in fluid communication with the borehole. Since an inflow
of fluid from the earth formations is apt to ccmprise the most
troublesome type of fluid flow between the interior of the borehole
and the reservoir, in some instances it may be desirable to
pressurize the interior of such a barrier or sheath to prevent
and/or terminate such an influx of fluid. Preferred gases for use
in such a pressurization ccmprise nitrogen or the noble gases or
the like. The material which surrounds such a barrier and contacts
the reservoir formation should be substantially heat resistant and
relatively heat-conductive at temperatures in the range of from
about 600 to 1000 C. Heat resistant cements or concretes are
preferred materials for such a use in the present process. Suitable
cements are described in patents such as US patent No. 3,507,332.
We have found that a number of inefficiencies in the thermal
con &ction process may occur in heterogeneous zones of formations
such as the Belridge diatomite. Different formation thermal
conductivities can result in uneven heater temperatures. Due to
copper electric properties, a higher heat injection would take
place into a less heat conductive "richer" layer than into a more
conductive "pcorer" layer. Since thermal conductivity is a function
of bulk density, more porous diatomite zones would receive more
heat than less porous ones. This would be undersirable as the more
porous zones are also more permeable and an efficient process is
possible in them at relatively low temperatures providing less heat
input.
If a constant cross section heater is used in extreme cases,
heat injection in the richer layers would continue after the
process was completed in them. In the poorer layers not enough heat
would be injected.
Therefore, a considerable improvement in process oil recovery
and heat efficiencies can be obtained by providing relatively
increased heat injection rates into the poorer layers which are
less porous and less permeable. This can be achieved by using a
variable cross section ccpper heater and/or using parallel heating
lZ~34 ~2
- 20 -
cables and positioning more of them along the poorer layers than
along the richer layers, or using other means for varying the rate
of heating.
To illustrate the effect of permeability on process
performance, mathematically simulated production functions for
three layers of different permeabilities but the same other
properties, are shown in Figures 6 and 7. The difference between
the two cases is in heat injection rates. In Figure 6 heat
injection rates were the same for all per~eabilities. The rates
]o were, in watts per metre: 500 for 3 years; 410 for 3 years; 330 for
2 years and 250 for 3 years.
In Figure 7 the rates of heat injection were different, in the
1 and 2 md layers they were decreased while for the 0.3 md layer
they were increased. The rates into the 1 md layer we~re decreased
by 10~, the rates into the 2 md layer were decreased by 15% and the
rates into the 0.3 md layer were increased by 15%.
In first case, (Figure 6) heat was injected for 11 years. It
may be seen that heat was continued ~o be injected in the most
per~eable layer, even though no additional oil could have been
produced from it while not enough heat was available in the least
permeable layer to complete the process.
In the second case, (Figure 7) heat was injected until all
layers provided the same recovery, while the overall heat
consumption decreased. Although there was a delay in process
ccmpletion in the 1 and 2 md permeability layers, the 0.3 md
permeable one had a big improvement in oil recovery as well as
process campletion time.
A summary of process oil recovery and heat efficiencies is
given in Table 2.
:` ~z~4~2
- 21 -
Table 2
SUMMARY OF PR0CESS OIL RECOVE~Y AND HEAT EFFICIENCIES
Same Layer Heat Input Modified LaYer Heat Input
Layer (md) 0.3 1.0 2.0 0.3 1.0 2.0
Oil Recovery (%) 8 84 84 83 83 83
Heat Eff. (10 kJ/
stock tank barrel oil) 421 398 400 427 380 339
Process Completion
Time (Years) 22 12 10 14 13 12
The improvement in heat efficiency indicated by the
simulations amounted to about 10~. This suggests that use of the
present modified heat input procedure may provide savings in the
order of 10-15% in the recovery of a given amount of oil from
reservoirs of the specified type.
In a preferred procedure, determ m ation of layer heat
injection rates in a given situation would be based on all known
formation properties, as well as economic analysis. In some cases,
overinjecting in some layers to cbtain earlier oil production might
be economically justifiable.
