Note: Descriptions are shown in the official language in which they were submitted.
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BACKGROUND OF THE INVENTION
This invention relates to thermal recovery processes for
recovering oil from underground formations, where steam, hot water or
any other hot liquid or gas is used to heat the oil in the resexwoir,
thereby reducing the viscosity of the oil and allowing the oil to be
recovered at economic rates. The invention is especially suited to
(but not limited to) the recovery of highly viscous oil or heavy oil,
wherein significant viscosity reduction upon heating occurs, and will
hereinafter be described in that context. Heavy oils typically have
a viscosity in excess of about 100 cp at initial reservoir
temperatures.
There are many oil reservoirs in the world which contain heavy
oil with such high viscosities that the oil cannot be produced using
conventional production methods. Large deposits of this type are
located in the Province of Alberta, Canada. Many methods of enhanced
production from these reservoirs have been documented including steam
injection, solvent injection, in-situ combustion and electrical
heating.
One of the more common methods of recovering heavy oil, by
employing steam injection, is referred to as cyclic steam stimulation
(CSS). CSS involves continuous injection of steam into a well for a
period of several days to a few months. Following the injection
period, the well may be shut-in for a period known as the soak
period, then the well is brought on production for an interval
varying from several days to several months. Subsequently, the cycle
of injection, soak and production is repeated. The injection of
steam enhances heavy oil production by (i) heating the oil, thereby
reducing its viscosity and allowing it to flow into the wellbore more
readily, and (ii) enhancing reservoir drive mechanisms such as
compaction, steam flashing, solution gas and thermal expansion.
A second common thermal recovery method is known as steam
drive. In this method a pattern of wells is employed which includes
some wells dedicated to continuous steam injection and others
dedicated to continuous fluid production. Again, production of heavy
~~ ~. ~~ ~~ ~ ~i
- 2 -
oil is enhanced by heating. However, the drive mechanism is now a
result of a pressure drop between in3ection wells and production
wells.
Often, CSS processes can only recover economically a relatively
small fraction (20-30X) of the overall oil in place. This econ~~ic
life of a process is limited by the efficiency with which the heavy
oil is recovered. Efficiency is commonly measured in terms of the
volumetric oil (produced) to steam (injected) ratio (OSx), which
inevitably decreases with time. While this low economic recovery can
be attributed to many factors, a primary consideration is both
horizontal and vertical conformance. Or stated simply, most of the
oil tends to be produced from localized regions while other regions
remain unaffected. In the later stages of CSS processes, steam tends
to flow more readily into zones which are already hot and from which
much of the oil has previously been produced. The process would be
more efficient and economical if the steam could be directed to the
cooler regions in the reservoir which still have high heavy oil
saturations by control of the high permeability paths created by
fracturing the formation, thereby increasing areal and/or vertical
conformance.
In both CSS and steam drive processes, fracturing may occur
during steam injection. Indeed, it is often necessary to in3ect at
pressures that cause fracturing in order to inject steam at a rate
which will allow economic production of the heavy oil. While in the
past fracturing has been considered necessary for economic reasons,
it has typically been avoided wherever possible for technical
reasons. However, a number of patents have previously been granted
for processes where fracturing is exploited as a mechanism for
creating high permeability paths in reservoirs. representative of
these are Canadian Patent ftos. 1,235,652 (Harding et al.) and
1,122,113 (Britton et al.); and U.S. Patent No. 3,330,353 (Flohr).
However, none of these adequately provides for both increased and
controlled areal and/or vertical conformance.
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SUMMARY OF THE IftVENTIOft
The present invention is based upon the discovery that by
injecting at rates that are high enough to initiate fracturing and by
controlling the rate of steam injection and the duration of the
injection period (or equivalently the volume injected), the eXtent of
both the fracture and the heated zone can be designed and
controlled. The previously unheated reservoir can be heated and the
heavy oil in the region can then be mobilized and produced.
Fractures that are created during steam injection can usually be
classified as leak-off dominated fractures, which are defined as
fractures where the rate of fluid flow injected into the fracture is
approximately equal to the rate of fluid loss from the fracture and
the rate of fluid storage in the fracture is small compared to the
injection anc~ leak-off rates. Equations governing leak-off and
storage dominated fractures are given by Geertsma and Deklerk, as
more specifically described hereinafter. For leak-off dominated
fractures, considering only single-phase flow, the areal extent Af,
is given by a simplification of Carter's Model (Howard, G.C. and
Fast, C.R.: "Optimum Fluid Characteristics for Fracture Extension",
Drill. and Prod. Prac., API (1957) 261):
Af - Qi (~rct)1/2 (1)
~r~cAP
where Qi is the injection rate (commonly quoted in units of m3/day,
1 m3/day = 1.16~10-5 m3/s, in which case Af would be quoted in units
of m2) cold mater equivalent volume; ~c is the fluid mobility of the
injected fluid in the formation and is equal to k/u, where k is the
permeability (units of Darcies, 1 Darcy = 1D = 10-12 m2), a is the
apparent viscosity of the fluid (units of cp, 1 cp = 1 mPa~s = 1'10-3
Pa's); DP is the difference between the injection pressure or
fracture pressure and the reservoir pressure (units of MPa, 1 MPa =
106Pa); c is the pore pressure diffusivity (units of m2/s or m2/day)
and t is injection pulse duration (units of seconds or days).
Utilizing this relationship in the method of the present
invention allows injection rates and volumes to be designed
appropriately. Critical to the present invention are the following
'I ~
.~ ~ ~~ :~ J
_4_
properties of leak-off dominated fractures: they have extremely high
fluid conductivities or effective permeabilities; the primary factor
controlling their orientation and direction of propagation is the
stress state in the formation; and because the fractures are a
parting of the formation, the heat capacitance of the fracture is
limited (compared to even a thin but highly permeable layer of sand
or rock), which allows heat to be transported effectively along
fractures.
To maximize the heat flux into the fracture (and minimize the
flux into the previously heated zone).it is advantageous to
periodically insect the steam in a series of pulses (i.e. at high
injection rates for short periods of time) rather than at a lower
continuous rate. If Qbp is defined as the rate at which steam can be
injected into a well at 3ust below the pressure required to initiate
a fracture, during high rate injection when steam enters the well at
a rate Qi, the fraction of the steam entering the fracture (a measure
of the efficiency of this process) can be estimated as (Qi-Qbp)/Qi.
Therefore, the efficiency with which fluid is directed into the
fracture as opposed to the previously heated zone increases with
increased injection rates.
It can be determined from Equation (1) that as Qi is increased,
the areal extent of a fracture for the same volume of injection
increases. 1"he duration of high-rate injection pulses should be
limited or designed so that the fractures extend to the desired
radius and do not adversely affect performance of surrounding wells.
Pulsed injection therefore provides an especially efficient and
controlled method in accordance with a preferred embodiment of the
invention for improving thermal conformance in heavy oil reservoirs.
Thus, in its broadest terms, the invention may be summarized as
a thermal recovery process for oil situated in an underground
formation which comprises:
(a) providing an injection/production well in fluid '
communication with said formation;
(b) establishing a desired maximum rate of injection Qi of
fluid into said formation to horizontally fracture said formation;
~'~ ~ ~" 'r~ ~ J
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(c) calculating for said injection rate Qi the duration t of
said injection to provide a desired pattern or areal extent of
fracture extending from said well, and
(d) injecting one or more pulses of fluid through said well
at said rate Qi, each for said period of time t as calculated i~i'step
(c), in order to fracture said formation.
The invention is especially effective in the recovery of heavy
oils having viscosities in excess of about 100 cp at initial
reservoir temperatures.
One simple method to calculate the areal extent Af (or
conversely, to calculate the time t for a desired area Af) is to
apply Equation (1) as described above. If it can be assumed that the
fracture is circular, then Af = ~rr2 where r is the radius of
fracture. Then, for a desired fracture radius r, the injection pulse
time duration t is calculated according to the formula:
1/2
r = Q ~ (~rct)1/4 (2)
Expressed in terms of t, this becomes:
-2 r4 (2a)
t =
~cAP ~ ~c
In some situations, the formula above may be an
over-simplification of the inter-relationship between Af, Qi and t,
for optimization of the fracture pattern or areal extent.
Alternatively, one may employ any or a combination of (i) more
complex analytical models, (ii) numerical models or (iii) empirical
relationships based on field data (i.e, data from observations), to
establish the inter-relationship between Af, Qi and t. Furthermore,
a key consideration in optimizing the fracture extent is the
distribution of heat deposition in the reservoir. Therefore, one
must consider the temperature profile or heat distribution along the
fracture which typically requires any or a combination of (i) more
complex analytical models, (ii) numerical models or (iii) empirical
relationships, as well, if it is found that Carter's model does not
provide the required level of optimization.
~1144~~
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Assuming one has reasonable estimates of the thermal properties
of the formation, as well as those properties identified in Equation
(1), the temperature distribution along a fracture and the heated
zone around it can be estimated using relatively simple analytical
models (e.g. Boone, T.J. and Bharatha, S.: "Temperature '°
distributions along Propagating Leak-Off Dominated Fractures," SPE
25791, First presented at the Thermal Operations Symposium,
Bakersfield, CA, February 1993). However, the heat distribution may
also be determined using any or a combination of (i) more complex
analytical models, (ii) numerical models or (iii) empirical
relationships, as well.
Preferably, the fluid is steam, either alone or in combination
with cold or warm water ix~ ections. Cold or warm water serves to
transfer heat from hot portions of the resexwoir to colder reservoir
portions, thereby increasing thermal conformance and allowing more
oil to be recovered at a potentially lower cost compared to steam
in3ection only.
The injection fluid may also be hot or cold water without the
presence of bteam. In the case of cold water, it is assumed that it
would be heated as it flows through the formation.
As yet a further alternative, the injection fluid may be a gas,
for example one produced by combustion of hydrocarbons with air or
oxygen. In this case, significantly higher injection rates with
shorter durations may be achieved.
For the reasons discussed above, maximum efficiency is attained
by in3ecting the fluid at a high rate - preferably at least 1,000
m3/day of cold water equivalent fluid volume and more preferably at
least 2,000 m3/day - for short periods of time. Indeed, the rate of
in3ection should be as high as possible, consistent with the
practical and economic constraints imposed by existing facilities.
For economic.and practical purposes, the preferred injection rate is
up to about 3,000 m3/day of cold water equivalent fluid volume but '
much higher rates are attainable (and would be desirable) by
modification of existing facilities).
The injection pulse duration may be from a few hours to several
days but for most formations is preferably from about 3 to about 24
_,_
hours. Generally speaking, as cumulative injection and production
from a well increases, it is found that pulse durations should also
increase and'may eventually become measured in days, rather than
hours. Nevertheless, the invention enables maximum efficiency to be
maintained by continued application of the high rates of injection.
If desired, the formation may be pre-pressurized and heated by
low rate steam injection prior to high-rate fracturing injections, in
order to increase the horizontal stress and thus the likelihood that
fracturing will occur horizontally.
Vertical conformance can be improved by recompleting or
reperforating the well at new locations along the wellbore.
In some situations it may be desirable to initially operate the
well for one or more fluid in3ection cycles at conventional in3ection
rates and then in a subsequent cycle to implement the high injection
rates enabled by application of the present invention. Thus a
recovery schedule for a given formation might consist of (i) one or
more cycles of conventional CSS, (ii) followed by implementation of
pulsed injection employing high injection rates with pulses of less
than 24 hours (with or without pre-pressurization); and (iii)
eventually increasing the duration of the pulses to several days
whilst maintaining the high injection rates consistent with maximum
efficiency. The precise conditions for recovery from a given
formation will dictate the chosen schedule and will be reflected by
the calculations performed in order to maximize the infection rates,
as herein described.
BRIEF DESCRIPTION OF THE DRAWINGS
Figure 1 illustrates the stages in a conventional CSS process
and also the stages in a high-rate pulsed injection process according
to a preferred embodiment of the invention;
Figure 2(a) is an areal plot of a well and a surrounding heated
zone and fracture pattern that develops during a conventional CSS or
steam drive process;
Figure 2(b) is an areal plot of a well and a surrounding heated
zone and fracture pattern that develops with high rates of injection;
_8_
Figure 3 illustrates how cold or warm water injection and
fracturing ct~n be employed as a means of increasing thermal
conformance;
Figure 4 illustrates the layout of an injection well and a
series of observation wells, and illustrates the extent of previously
heated zones surrounding such wells;
Figures 5 and 6 are respectively plots of temperatures and well
head pressures measured at an observation well D3-OB2 during
conventional CSS processing;
Figure 7 is a plot of typical injection rates and injection
pressures during a six hour high-rate pulse performed in accordance
with the invention;
Figure 8 is a plot of temperatures measured at observation well
D3-OB2 during a test of high-rate pulsed injection in accordance with
the invention;
Figure 9 is a plot of temperature change measured at selected
thermocouples on observation wells D3-OB2 and D3-OB4 during a
high-rate pulsed injection HRPI test;
Figure 10 is a plot of temperatures measured at observation well
D3-OB6 during the HRPI test;
Figure 11 illustrates the areal extent of the fracture resulting
from the HRPI test;
Figure 12 illustrates a series of temperature profiles from
successive surveys at observation well D3-OB1 during the HRPI test;
Figure 13 is a plot of bottom hole pressures measured at
injection well D3-8 during the HRPI test;
Figure ''4 is a plot of pressures at well D3-8 and five
observation wells during the final pulse of tha. HRPI test; and
Figure 15 illustrates a further preferred embodiment of the
invention directed to improvement in vertical conformance.
DESCRIPTIOft OF THE PREFERRED EMBODIMENTS '
Heavy oils found in the Clearwater formation near Cold Lake,
Alberta have been produced using CSS. Typically this process has
consisted of repeated cycles where between 5,000 m3 and 20,000 m3
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(cold water equivalent volumes) of steam are injected into a vertical
well. Subsequently, the well has been placed on production for
periods ranging from a few months to more than a year, the injection
rates typically being between 200 and 300 m3/day. Initially, these
rates are sufficient to immediately fracture the reservoir. However,
as the cycles progress, the rate at which the pressure increases
during injection decreases and it generally takes significant volumes
of infected steam before the pressure reaches a level where the
reservoir fractures. Eventually, one can expect that at these
injection rates the entire volumes of steam will enter the formation
without fracturing. As one would expect, with progressive cycles,
the effective permeability of the saad matrix to steam and water
increases significantly as the bitumen is extracted. An associated
implication is that the hot water and steam are preferentially
flowing through channels and zones in the reservoir which have high
water or gas saturations and have, therefore, been depleted of their
bitumen. As a result, the heat carried by the water and steam is
deposited in regions of the reservoir which have relatively low
bitumen saturations. This typically manifests itself as a decline in
the oil to steam ratio (OSx) as cycles progress.
At Cold Lake, it has been estimated that only 20X of the oil in
place can be economically recovered using CSS. The formation
consists of a sand with an absolute permeability of 1D and 35X
porosity which is initially 70% saturated with bitumen. The
bitumen's viscosity is approximately 100,000 cP at the ambient
reservoir temperature of 13°C. A major impediment to increasing this
recovery level is the inability to uniformly distribute heat in the
reservoir and thereby attain an optimal thermal conformance. When
the economic limit of CSS is reached, large volumes within the
reservoir will remain near ambient temperatures with high bitumen
saturations. A simple, but relatively costly, solution to the
problem is to drill more wells. Alternatively, one can devise
infection strategies that fundamentally alter the distribution of
heat deposition in the reservoir. When in3ecting at rates below the
fracture pressure, especially in later cycles, it is the formation's
effective permeability to water and steam which is controlling where
~~.~.~4~~
-lo-
heat is deposited in the reservoir. Fundamentally, when injecting
heat through steam-induced fractures, it is the stress state which
controls the orientation and shape of the fractures and, therefore,
the deposition of the injected heat. The injection strategy
described herein is designed to exploit high-rate injection and~°
fracturing to preferentially deposit heat in the previously
uncontacted regions of the reservoir.
Previous fracture tests and observations made in the Alberta oil
sands have involved inducing fractures from as injector and
monitoring observation wells, or subsequently drilling observation
wells to determine the extent, shape and orientation of the
fractures. The results have generally indicated that these fractures
are not confined to vertical or horizontal planes. A conclusion that
can be drawn from these results is that the three principal stresses
are nearly equal in these formations.
Factors Controlling Steam-Induced Fractures
The following is a brief overview of the fundamental principles
that either control or influence fractures in the reservoir and the
associated deposition of heat. Oil sands differ from most reservoir
rocks due to their lack of cementation or cohesion between grains.
However, ma~,y of the fundamental factors which control fractures is
rock are applicable to sands as well. For example, the extent of a
leak-off dominated fracture can be estimated by balancing the
injection rate with leak-off from the fracture and the fracture can
be expected to orient itself perpendicular to the minimum principal
stress thereby minimizing the in~ectioa pressure.
First, the extent of fracture propagation can be predicted using
the special case of Carter's model for leak-off dominated fractures
[Howard and Fast] described above. The area, Af, is expressed as a
function of time, t, as follows:
(1)
Af(t) = Q (~rct)1/2
where Qi is the injection rate, DP is the difference between the
injection pressure Pi and the initial reservoir pressure Po, ~c is the
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fluid mobility and c is the pore pressure diffusivity of the
formation. The fluid mobility ~c is equal to k/u where k is the
permeability (Darcies) and a is the apparent viscosity of the fluids
in centipoises. Alternatively, one can substitute V = Qit where V is
the volume of the injected fluid and attain:
Af(t) = 1 ~ ~~rcQiV 1/2 (3)
~r~cA [,P
Equation (3) demonstrates that fracture area can be increased by
increasing the injection rate and maintaining constant volume. i~lhen
ix~jecting steam, Equations (1) and (3) can be reasonable
approximations if it is assumed that the steam condenses at or near
the fracture~face. Given this assumption, it is appropriate to
employ the equivalent cold water injection rate and the effective
permeability to water in the formation.
It has recently been shown that the temperature distribution
along fractures of this type are bounded by self-similar profiles
(Boone, T.J. and Bharatha, S.: "Temperature Distributions Along
Propagating Leak-Off Dominated Fractures", SPE 25791, First presented
at the 1993 Thermal Operations Symposium, Bakersfield, CA, February
1993). These profiles are referenced to the current fracture area
and are independent of time and injection rate. This allows one to
first estimate the extent of the fracture from Equation (1) and then
estimate the interior region which has been heated. One can also
make estimates of the arrival time of heat at a point in the
reservoir and the quantity of heat that will be deposited. Most
importantly, it becomes apparent that, while one can control rate and
infection period in order to optimize placement of heat in the
reservoir, one also requires knowledge of the effective permeability
of the formation to the in3ection fluid.
Geertsma and DeRlerk (Geertsma, J. and DeKlerk, F.: "A rapid
Method of Predicting Width and Extent of Hydraulically Induced
Fractures", JPT (Dec. 1969) 21, No. 12, 1571-1581) provide some
simple equations, based on an assumed logarithmic pressure
~~.~~4~
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distribution in a radial fracture, for estimating the fracture width
at the wellbore, wf:
wf ~ 2 uQ;a 1/4
l G
where Qi is the injection rate, x is the fracture radius, G is the
shear modulus for the formation and a is the viscosity of the
in3ected fluid. The average fracture width is 2wf/3. At the well
bore the fracture width, given parameters appropriate for Cold Lake
and a fracture radius of 60 m, is between 1 and 2 mm. The pressure
distribution in the fracture, Pf, is given as:
Pf(r) = Sn - ~ ln(r) (5)
4tt8 x
where r is the radial distance from the center of the wellbore and Sn
is the stress normal to the fracture. For the fractures at Cold
Lake, this equation implies that the pressure at the perforations
(r = 0.1 m) ~,s only 0.1 MPa greater than Sn; (1 Ira = 106Pa).
The effective permeability at a point along a fracture is simply
w2/12 where w is the width of the fracture at that point. Assuming a
1.3 mm fracture width at the wellbore, the effective permeability is
150 kD and multiplying by the width, the inventors determined a
fracture conductivity of 200 Darcy-meters (D-m). This compares with
a typical reservoir conductivity of 50 D-m, assuming 1 D absolute
permeability and a 50 m thick reservoir. It may be more appropriate
to compare the fracture conductivity to the reservoir's effective
conductivity to water at its residual oil saturation which is
estimated to be 2.5 D-m. Clearly, a steam-induced fracture in oil
sands has orders of magnitude greater permeability than any expected
communication channels in the formation.
Equation (1) is based on the assumption that there is negligible ..
fluid storage within the fracture so that the rate of fluid injection
is balanced exactly by the rate of fluid leak-off. This dictates the
areal extent of the fracture but not its shape. As a general
principle, a fracture will extend in a manner or shape that minimizes
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the injection pressure and, therefore, the energy required to inject
the fluid into the formation. Typically, this means a fracture will
be oriented perpendicular to the minimum stress. Oil sands are
typically found at relatively shallow depths where vertical and
horizontal stresses are nearly equal. From a reservoir engix~eering
perspective, horizontal fractures are often favoured because they are
more effective at areally distributing heat and are contained with
the formation. One method of increasing the likelihood of horizontal
fractures is to increase the reservoir pressure before injecting at
rates which induce fractures. It is well known from practice and
simple elastic theory (Felsenthal, M. and Ferrell, H.H.: "Fracturing
Gradients in Waterfloods of Low-Permeability, Partially Depleted
Zones", JPT (June 1971) 727-730) that both pressurizing and heating
of the reservoir tend to increase the horizontal stresses more than
the vertical stress.
Assuminl~ the fracture is horizontal, it will expand within that
plane in a manner or shape that minimizes the injection pressure. In
conventional fracture treatments, this principle is exploited in
cases where there are relatively high stresses, typically in shales,
that confine vertical fractures within the reservoir. Finite element
analyses incorporating temperature and pore pressure changes from
thermal reservoir simulations of the Cold Lake reservoir have shown
that areal variations in the vertical stress of 1 to 2 MPa are
induced by the CSS process. Both the areal variation in the vertical
stress and the pressure drop along the fracture will influence its
shape. However, given the limited pressure drops as estimated from
Equation 5, the areal variations in the vertical stress are likely to
be the dominant influence (which is supported by the field evidence
as hereinafter described and explained). This leads to the
conclusion that horizontal fractures will tend to propagate into
regions of lowest vertical stress. These are the regions with the
least change in temperature and pressure. This is a critical and '
highly desirable aspect of fracturing since it favours transport of
heat to previously unheated reservoir. Steam-induced fracturing is
potentially a mechanism for diverting heat away from the
high-permeability channels in the formation's matrix and into cooler
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regions of the reservoir where the effective permeability in the
matrix is still very low.
In uncemented oil sands, relatively large porosity increases can
occur especially under conditions of low effective stress.
Associated recompaction plays a significant role in bitumen recovery
as a drive mechanism. Finite element analyses have shown that the
region of highest porosity change is in the near vicinity of the
fracture faces. This can be attributed to three factors: high
temperatures, high pore pressures and low effective stresses. While
high temperatures and high pore pressures may occur elsewhere due to
flow through the sand matrix, the boundary condition normal to a
fracture face is necessarily zero effective stress. These large
porosity changes allow for increased effective permeabilities and
fluid storage near the fracture face. As a result, a smaller
fracture area is required to balance the injection rate and leak-off
from the fracture (Settari, A., P.B. Kry and C.-T. Yee: "Coupling of
Fluid Flow and Soil Behaviour to Model In3ection into Uncemented Oil
Sands", J. Can. Pet. Tech. (Jan-Feb. 1989) 28, No. 1).
High-rate Pulsed Infection
During steam in3ection into oil sands, one can control
relatively few parameters at a specific well: rate; volume; and
energy content. To date, steam strategies have focused on exploiting
infection volumes along with field-scale steaming patterns (Gallant,
x.J., Stark, S.D., and Taylor, M.D.: "Steaming and Operating
Strategies ar. a Mid-Life CSS Operation", (SPE 25791, First presented
at the 1993 Thermal Operations Symposium, Bakersfield, CA, February
8-10, 1993). In an especially preferred embodiment, the present
invention uses high-rate pulsed in3ection (HBPI) as a tool for
improving areal thermal conformance. In essence, the concept is that
(1) high injection rates cause the formation to fracture; (2) the
shape and orientation of fractures in the reservoir are controlled by
the stress state (rather than existing high permeability channels);
(3) by controlling the injection rate and pulse duration, the extent
of fracture propagation can be controlled; and (4) in turn, through
~~.~~~~5
- 15 -
knowledge of the heat transport capabilities of fractures, heat can
be placed optimally in the reservoir.
Conceptually, the injection strategy is illustrated in
Figure 1. Typically, a CSS cycle consists of an infection period at
a constant rate followed by a soak period and then a much longer
period of production. HRPI involves altering only the injection
period so that rather than in3ecting continuously at typical rates
(200-300 m3/day), steam is in3ected at high rates for periods which
may be from a few hours to several days. For most formations the
duration of steam in3ection is preferably between three and 24 hours
at rates of from 2,000-3,000 m3/day. Between pulses, the well can be
shut-in or itt3ection can be maintained at a nominal rate.
At typical injection rates, it was expected that, if a fracture
was induced, it would likely be confined within the existing heated
(depleted) zone as shown in Figure 2(a). At high injection rates, a
fracture extends well beyond the existing heated zone and thereby
improves areal thermal conformance as shown in Figure 2(b).
Essentially, by injecting at high rates, one overwhelms the
formation's capacity for accommodating flow through the matrix.
Figure 3 shows how cold water injection and fracturing can be
employed as a mechanism for increasing thermal conformance. The cold
water is heated as it passes through the heated zone near the
wellbore and deposits that heat outside that zone in cooler regions
of the reservoir. Thus, heat is transferred from hot portions to
colder portions of the reservoir thereby increasing thermal
conformance and allowing more oil to be recovered at a potentially
lower cost than steam injection alone.
Since steam will be flowing from the well's perforations
directly into both the fracture and the formation, it is desirable to
maximize the in3ection rate and thereby the fraction of the flow that
is entering the fracture. The fracture pressure is effectively
limited by the minimum stress in the formation. It also limits the '
injection pressure and therefore the flow rate into the matrix. The
period for high-rate injection should be designed so that the extent
of the fractures and heat deposition are optimized. At very high
rates and for long periods, fractures could extend far beyond the
~.~~4~~~
- 16 -
ad3acent infection wells. The period between high-rate pulses allows
both pressure and temperature to diffuse away from the near vicinity
of the fracture layer.
Field Test of the Invention
The primary purpose of this field test was to prove that the
concept of controlled fracturing according to this invention is a
feasible mechanism for improving areal thermal conformance. The
location chosen for the test was an injection well that had completed
seven cycles. of the cyclic steam stimulation prior to the test (see
Table 1 below). The well was also surrounded by six observation
wells which had provided temperature and pressure histories during
the previous five years. The location was also unique since 3D
seismic imaging had been used to identify anomalous zones around the
injection wells during the sixth cycle of production. Based on prior
stress tests in this reservoir and previous injection pressures, it
was expected that horizontal fractures would be induced. The layout
of the injection well, known as D3-8, the surrounding observation
wells, D3-OB1 through D3-OB6 and the zones imaged from the 3D seismic
work are shown in Figure 4.
To prove the feasibility of the invention, it was required that
(i) it be clearly demonstrated that horizontal fractures were induced
and (ii) it be shown it is possible, given facility constraints and
the depleted state of the reservoir, to propagate the fractures and,
thereby, transport heat into the undepleted regions of the reservoir.
In cycles one through six of the prior cyclic steam stimulation,
injection volumes averaged about 8,000 m3 of steam and, in the
seventh cycle, the volume was increased to approximately 19,000 m3 as
summarized in Table 1:
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Table 1
IftJECTIOft VOLUMES AftD PRESSURES BY CYCLE
AT WELL D3-8
.<
___~______ s _--
_
Typical ~ Maximum
o Volume ~ I~ection ~ Injection
Injected~ Pressure , Pressure
i Cycle (m3) ~ (MPa) 3 (MPa)
~_~-________.~__ _._.~~_.____~.__..____-_.____________~___
.__ __
I s ;
1 7932 ' 10.5 ~ 10.7
j 2 7027 ~ 11.0 ~ 12.1
3 8034 ( 11.0 ~ 12.0
c 4 i 7904 ~ 10.0 ~ 10.7
i 5 ~ 10113 ~ 8.5 to 11 11
!
6 ~ 7741 ~ 8 to 8.9 ~ 8.9
7 g 18723 ~ 9.5 to 11 11
~
8(HRPI) ? 17200 ~ 12.2-12.5 12.6
~
-_'-.__._______.~__.~'~~~___~____T.______..__.___.._____,_______._____
Approximately equivalent volumes were injected into the other
operating wells on the pad. Injection rates during each of these
cycles were typically between 200 and 300 m3/day.
The six observation wells surrounded D3-8 as shown in Figure 4.
Each of the observation wells had thermocouples attached to the
casing and cemented in place when they were installed. The
Clearwater oil sands are approximately 55 m thick at this location
between depths of 420 and 475 m. Six thermocouples were installed in
each well at approximate depths of 0, 10, 20, 30, 40 and 50 m below
the top of the Clearwater. Each of the observation wells, except
D3-OB6, was perforated over an eight meter interval at a depth of 459 '
to 467 m, wh3~ch allowed measurement of the reservoir pressure through
the annulus. Measurements of temperature and pressure were typically
recorded four times daily.
- 18 -
The down hole temperature responses and wellhead pressure
responses measured at observation well D3-OB2 between 1986 and 1991
are plotted in Figures 5 and 6. These plots are also representative
of the other observation wells. During an injection cycle, the
wellhead pressures rose to between 4 and 5 MPs which equates.to~-
bottomhole pressures between 8.6 and 10.6 MPs. The observed
temperatures remained below 50°C except for occasional spikes in the
early cycles and D3-OB6 which saw temperatures up to 120°C during the
seventh cycle. This temperature response at D3-OB6 was attributed to
communication with an injection well to the northeast (D3-3 or D3-4)
rather than D3-8 which is southwest of the observation well.
Table 1 lists typical and peak wellhead pressures at the
injector, D3-8, for each cycle. These pressures were between 0 and 1
MPs above the bottom hole pressure. Based on plots of wellhead
pressures for each cycle, it can be inferred that fracturing likely
occurred during most of cycle one to three and parts of cycles five
and seven. It is unlikely that fracturing occurred during the fourth
and sixth cycles. The original vertical stress at the perforation
depth of D3-8 was estimated at 9.7 MPs from density logs. The
wellhead pressures were consistent with the expectation that
horizontal fractures had been induced in the reservoir.
A 3D seismic survey, centered at D3-8, was performed
approximately four months after the completion of sixth cycle
injection. Figure 4 plots the approximate limit of the 60°C contour
for the region surrounding D3-7, D3-8 and D3-9 based on
interpretation of the seismic image and comparable numerical
simulations. This interpretation was consistent with the observed
temperatures at the surrounding obsexwation wells. All the
observation wells were outside what is interpreted as the 60°C
contour with D3-OB2 located closest to the zone. This layout was
fortuitous far the purposes of the test described below since the
observation wells were ideally positioned for observing heat '
transported outside the previously heated zone by steam-induced
fractures.
The HRPI test (cycle 8) was initiated at noon on December 16,
1991, after D3-8 had been steamed for about one week at a rate of
- 19 -
approximately 200 m3/day. Steam injection at D3-8 and the
surrounding wells, prior to the test, raised the reservoir pressure
to approximately 5 MPa. A series of 21 injection pulses were then
performed at~approximately two day intervals with most pulse
durations being close to six hours. The first series was followed by
two 24 hour pulses which were 11 days apart. Figure 7 plots
injection rates and the wellhead pressure recorded during a typical
pulse. With relatively limited modifications to existing facilities,
maximum rates exceeding 2000 m3/day were attainable. The rate
typically decreased from 2000 m3/day to approximately 1700 m3/day
during each pulse. The wellhead pressures increased gradually during
this period. This increase can be attributed to poroelastic effects
or backstress which caused the stress normal to the fracture and,
therefore, the fracture pressure to increase with time (Boone, T.J.,
Rry, P.B., Bharatha, S., and Gronseth, J.M.: "Poroelastic Effects
related to Stress Determination by Micro-frac Tests in Permeable
Rock", 8och Mechanics as a Multi-Disciplinary Science, Proc. of the
32nd U.S. Bock Mechanics Symposium, J.C. xoegiers (ed.), Norman OR,
(1991)). The increasing injection pressure combined with facility
constraints caused the injection rates to decrease.
The temperature responses from the thermocouples at D3-OB2 are
plotted in Figure 8. Note that prior to the start of pulsed
injection, the temperature at the 40 m thermocouple increased from
40°C to 110°C then declined to 80°C. Given the close
vicinity of the
heated zone to D3-OB2, as determined from the seismic image in Figure
3, this initial thermal communication was not surprising.
Cyclic temperature response was apparent from the start of
pulsed injection at wells D3-0B1, D3-OB2 and D3-OB4, as can be seen
for D3-0B2 from Figure 8. Each pulse was characterized by a rapid
temperature increase at these three observation wells. Figure 9
plots the temperature response at selected thermocouples from D3-OB2
and D3-OB4 during the first pulse. They showed significant response '
within hours of commencing the test. Wells D3-OB3 and D3-OB5
apparently were not contacted by hot fluids at suvy time during the
test and did not show any significant temperature response. The
response at D3-OB6 is plotted in Figure 10. It appears to be
CA 02114456 2003-11-06
- 20 -
communicating with one of the other in~ectioa wells as it had on the
previous cycle. However, superposed on this response is a clear
signature from pulsed infection at D3-8 as evidenced by the spikes in
the 20m and 30m plots. Initially, the response is negligible but
after approximately tea pulses it becomes quite distinct. Oae can
speculate that either initially the fracture did not intersect D3-OB6
or, if it did, the fluids were at reservoir temperatures.
Subsequently, either the fracture grew to the point it intersected
D3-0B6 or, if the fracture had intersected it initially, heat began
to be transported to D3-0B6.
The observation wells showed temperature responses through much
of the thickness of the reservoir. However, it would be expected
that the fracture would only heat a very narrow zone. The broader
temperature ~espoase at the observation wells was attributed to a
fracture intersecting the wellbore at or near the perforations.
Fluid can they flow into the wellbore, compressing gas at the top of
the wellbore and it can potentially flow through pathways along the
exterior of the casing or cement. This broad temperature response
is, therefore, an artifact of the observation wells. However, it is
somewhat advantageous since it negates the need for detailed
temperature logging to determine if a fracture intersected the
observation well.
The rapid arrival time for heat at the observation wells was
highly indicative of fracturing. Given the infection rates sad steam
quality 070x), it was estimated using the model of Marx and
Laagenheim (Marx, J.N. and Langeaheim, H.H.: "reservoir Heating by
Hot Fluid I~ection", Trans. AIMS, Vol. 216, (1959) 312-315) that the
steam must be flowing through a channel ao more than a few
centimeters thick. Since there was no prior evidence of such
channels, it was reasonable to assume that it was a steam-induced
fracture.
Based oa the temperature response at the observation wells,
estimates of the fracture area were made. Assuming as elliptical
fracture, Figure 11 plots approximate extents of the fracture gives
that for the first 27 days (1) it intersects D3-OB1, D3-OB2 and D3-
0B4, and after 27 days (2) it also intersects D3-OB6. For the two
cases, the
/i t~ a ~ !a
- 21 -
areas were roughly 11,000 m2 and 15,000 m2, where the overlap with
the previously heated zone was about 5,000 m2 in each case. These
estimates of the fracture size are based on temperature
observations. However, the actual extent of the fracture could be
greater since it is likely that the injected fluid had cooled tos
reservoir temperature before it reached the fracture front and the
arrival of fluid at reservoir temperature would not be observed.
It is consistent with Equation (1) that the fracture area would
increase with successive pulses since the reservoir pressure was also
continually increasing. A larger fracture area was then required to
compensate for reduced leak-off. Similarly, as the region around the
fracture plazie was progressively heated, heat was transported to
larger areal extents with progressive pulses.
Finally, it is important to note that the fracture apparently
propagated away from the previously heated zone as determined from
seismic results and into a region of the reservoir which was
relatively cool and undepleted. This is consistent with the
assertion that the areal variation in the vertical stress would
control the fracture shape and promote fracture growth into regions
with lower pressures and temperatures.
Several temperature logs were taken at the obsexwation wells
during the test. Unfortunately, the presence of cold bitumen in
observation wells D3-OB2 and D3-OB4 prevented logging of these wells
on several occasions. The logs at D3-OB3 and D3-0B5 confirm that
there was not any significant heat transport to these wells. Figure
12 plots the temperature logs taken at various times for well
D3-OB1. These surveys show significant increases both at the interim
survey and at the final survey about 7 weeks later. The latter is
strongly indicative of fracturing, given the peak in the temperature
at a depth of 460 m, about 1 m above the top of the perforations at
D3-8 which extend from a true vertical depth of 461 to 469 m.
The temperature logs were integrated to provide estimates of the
change in the areal heat density at the observation wells. However,
due to convection of heat along the wellbore, it is apparent that the
data from observation wells overestimate the average change in heat
density that was occurring away from the well. The best estimate is
w
- 22 -
that approximately 50X of the total heat injected was deposited
outside the previously heated zone.
The bottomhole pressure response at the injection well, D3-08,
was measured down hole through a gas filled bubble tube contained
within the wellbore. The pressure response is plotted in Figure~l3
along with results from a simple numerical simulation. The field
data was analyzed in detail for each injection pulse except for some
pulses where the data collection system was not functioning. From
plots of the derivative of pressure with respect to time versus
pressure, both the fracture initiation pressures (Pi) and
instantaneous shut-in pressures (Pisip) or fracture closure pressures
could be extracted. As a general trend, both the Pi and Pisip tended
to increase with progressive cycles. The bottom hole pressure during
injection, 3ust prior to shut-in, typically exceeded the Pisip by
about 0.6 MPa.
The numerical simulation results are from a single well radial
model which assumed single phase flow. It also accounted for changes
in the vertical stress and the fracture pressure due to temporal
changes in both temperature and pressure throughout the reservoir
using an integral approach (Boone, T.J., Rry, P.x., Bharatha, S., and
Gronseth, J.M.: "Poroelastic Effect$ related to Stress Determination
by Micro-frac Tests in Permeable rock", xoch Mechanics as a
Multi-Disciplinary Science, Proc. of the 32nd U.S. Bock Mechanics
Symposium, J.C. xoegiers (ed.), Norman OR, (1991)). In spite of its
simplicity, the model produced a reasonable match to the pressure
response and captured the rise in injection pressure with subsequent
cycles. The match was attained with assumed effective permeabilities
of 1.1 mD vertically and 7 mD horizontally. The vertical
permeability was the primary factor controlling the areal extent of
the fracture and the horizontal permeability was what largely
controlled the pressure decline between cycles.
Figure 14 overlays the bottomhole pressure response at D3-8 with
that obtained from the observation wells during the final 24 hour
pulse. It shows a rapid but delayed response at the observation well
during each r~ulse. Wells D3-OB1 and D3-OB4 had similarly rapid
- 23 -
response whereas wells D3-OB3 and D3-OBS, which were apparently not
intersected by the fracture, responded more slowly.
The fracture initiation pressure (Pi) is identified as 10.7 MPa
in Figure 14 and the instantaneous shut-in pressure Pisip is 11.0
MPa. The latter was the best estimate of the fracture pressure-
outside the near wellbore region where most of the pressure drop was
expected to occur during injection. The pressure immediately dropped
by 0.6 MPa after shut-in to the value of the Pisip~ It was deduced
that the best estimate of the vertical stress at the time of fracture
initiation was 10.1 MPa or 0.6 MPa less than the value Pi. The
difference between the Pisip at the injector and the pressures
measured at the observation wells was only a few tenths of an MPa.
However, the pressure at the injectors and the observation wells were
at least 1 MPa greater than original estimate of the vertical stress
(9.7 MPa). These observations were consistent with the theoretical
expectations described above that there should be only a small
pressure drop along the fracture and an order of magnitude larger
areal variation in the vertical stress.
There were numerous observations that supported the hypothesis
that what in, essence were conventional, leak-off dominated fractures
were induced in the reservoir which was composed of uncemented oil
sands. In fact, this test was unique in terms of the variety of
tools and facilities that could be used to monitor and interpret the
behavior of the fractures. The evidence for horizontally-induced
fractures can be summarized as follows:
(1) Heat Transport: The rapid temperature response, as
illustrated in Figure 8, which occurred within hours of the
initiation of pulsed injection indicated that a thin highly permeable
channel formed in the reservoir. Based on the model of Marx and
Langenheim, one would expect that the channel must be no more than a
few centimeters in thiclrness. There was no prior evidence of a high
permeability channel at this depth.
(2) Infection Pressure: The maximum injection pressure was
comparable to that reached on previous cycles at much lower injection
rates. This was indicative of fracturing which essentially capped
the injection pressure at a value close to the stress due to the
- 24 -
weight of the overburden and independent of the formation's effective
permeability to the injected fluid.
(3) 'Fracture' Orientation: It was expected that with the
reservoir pressure at 5 MPa at the start of pulsed injection that the
stress state would favour horizontal fractures. At D3-OB1 the peak
temperature response on the final survey was at a depth of 460 m.
This is approximately one meter shallower than the top of the
perforations at the injection well which was 80 m away. The observed
response at the other three observation wells which saw significant
temperature changes was also consistent with a nearly horizontal
fracture.
(4) Changes in Injection Pressure: As the reservoir pressure
and temperature increased the fracture pressure should also increase
due to local changes in the vertical stress. The field data supports
this assertion since the fracture closure pressure as determined from
the Pisip increased from 9.5 to 11 MPa over the injection period.
(5) Numerical Simulations: The match between the injection
pressure and that determined from a simulated fracture model, Figure
12, adds credence to the fracture concept. In particular, the
effective permeabilities used to attain the match were consistent
with expectations and useful design parameters.
(6) Pressure Gradients: From the pressures measured during
the last injection pulse, it was determined that the Pisip was 11 MPa
which was the best estimate of the fracture pressure outside the near
wellbore region. At that point in time the pressures measured at
D3-OB2 and D3-OB4 were both 10.8 MPa, respectively. This small
pressure differential between the observation wells and D3-08 and the
rapid rise times for the pressures were also indicative of
fracturing. As discussed above, a pressure drop in the order of 0.1
l~a would be expected over the radius of a fracture. Fluid flow
through the matrix would be expected to give rise to much higher
pressure drops given the injection rate and lrnown matrix '
permeabilities.
(7) Areal Shape and Extent: Given the observed increase in
the fracture pressure, it was deduced that, in the reservoir, there
must be an areal variation in the vertical stress with a magnitude on
- 25 -
the order of 1 to 2 MPa. Since this is significantly greater than
the pressure drop along the fracture as determined from theory and
observation,'it follows that areal variations in the vertical stress
were controlling the fracture shape. This is consistent with the
field evidence, as shown in Figure 11, since the fracture propagated
away from the previously heated zone where the vertical stresses are
predicted to be greatest.
Vertical Conformance
Figure 15 illustrates how vertical conformance can be improved
by recompleting or reperforating the in3ection well at new locations
along the wellbore. There is shown firstly a depleted zone
underlying a high bitumen saturated zone. A re-perforation is formed
in the wellbore in communication with the high bitumen saturation
zone and an injection pulse is applied in the manner of the
invention. This provides a horizontal fracture extending from the
vicinity of the re-perforation and steam and heat are thus diverted
away from the depleted zone. Re-perforation can be repeated at a
number of levels in the formation, so that a series of horizontal
production zones results, with correspondingly improved vertical
conformance.
Imvlications for Thermal Reservoir Enzineerina
Some of the implications for thermal reservoir engineering
arising from the present invention are as follows:
1. It has been demonstrated that high-rate steam injection and
induced fracturing are an effective means of rapidly increasing areal
thermal conformance (even in eighth cycle CSS at Cold Lake).
2. It has been demonstrated that HRPI is a thermally efficient
mechanism since it is estimated that approximately 50~ of the
injected heat was placed outside the previously heated zone in the _
vicinity of the fracture.
3. Controlling the pulse duration provides a mechanism for limiting
the areal extent of fracturing and thereby the extent of areal heat
transport.
- 26 -
4. Pulsed in3ection provides a distinctive trace to communication
events so that they can be clearly tied to the source.
5. It has been demonstrated that at Cold Lake the fractures are
expected to remain nearly horizontal over radial distances of at
least 80 m. This confirms the potential to exploit HRPI as a ~-
mechanism for altering vertical conformance by re-completion at
various depths. Fractures can be expected to initiate at or near the
top of the perforated interval. By re-perforating, so that the top
of the perforations align with another zone of high bitumen
saturation, steam and heat can be diverted away from a connected zone
which has been previously depleted or initially had high water
saturation.
6. It has been shown that areal variations in the vertical stress
are the dominant mechanism controlling the fracture shape and that
this mechanism causes fractures to grow into regions of the reservoir
that were not previously heated. This leads to the conclusion that
HRPI preferentially deposits heat in the previously uncontacted
cooler reservoir.
