Note: Descriptions are shown in the official language in which they were submitted.
A8141029CADIV
INFILL WELL METHODS FOR HYDROCARBON RECOVERY
TECHNICAL FIELD
[0001] The present disclosure generally relates to infill wells. In
particular, the disclosure relates
to providing infill wells for recovery of hydrocarbons.
BACKGROUND
[0002] Various recovery techniques are used for in situ recovery of
viscous and heavy
hydrocarbons that are deep below a surface. Cyclic steam stimulation (CSS) and
steam assisted gravity
drainage (SAGD) are non-limiting examples of such recovery techniques that use
heat energy from steam
to mobilize the viscous and heavy hydrocarbons. A SAGD setup features a pair
of horizontal wells that
are generally parallel and vertically offset from one another (commonly
referred to as a well pair). The
well pair is drilled through or proximal to a pay-zone within a geological
formation that contains a
reservoir of viscous and heavy hydrocarbons. The well pair includes an upper
well configured for steam
injection (commonly referred to as an injection well) and a lower well
configured for collecting and
lifting fluids to the surface (commonly referred to as a production well).
During operation, steam is
injected into the pay zone from the injection well, which results in a
transfer of heat energy to the viscous
and heavy hydrocarbons within the pay zone. The transfer of heat energy
reduces the viscosity of the
hydrocarbons, thereby mobilizing them within the pay zone such that the
hydrocarbons flow toward the
production well, under the influence of gravity. This process forms a steam
chamber that grows generally
upward and outward within the pay zone. The physics of steam chamber growth is
influenced by an array
of factors relating to, but not limited to: the composition, heterogeneity,
porosity, and structure of the
pay zone and the features of the surrounding geological formation. As a
result, steam chamber growth
is often non-uniform and varies over time.
[0003] In commercial applications, multiple SAGD well pairs are typically
provided in a group
that extends from a single well pad at surface into one or more pay zones. The
well pairs of the group
often extend parallel to one another such that each well pair has one or more
laterally spaced-apart
neighbouring well pairs. As the SAGD process progresses over time, the steam
chamber of each well
pair increases in size. Because steam chambers generally progress upwardly and
outwardly, regions of
the pay zone that are low-lying relative to the injection wells are often not
heated sufficiently to mobilize
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the hydrocarbons therein. These regions are commonly referred to as bypass
regions, and they can
contain significant quantities of hydrocarbons that are not produced by the
production wells.
[0004] One known approach for producing the hydrocarbons within the
bypass region is an infill
well. An infill well is drilled between neighbouring sets of SAGD well pairs
to access heavy
hydrocarbons from the bypass regions. In many instances, infill wells are
drilled many months or years
after the pay zone is injected with steam. However, the drilling, completing,
and operating of infill wells
is resource intensive in terms of time, money, energy and equipment. As such,
considerations as to where,
when and the type of infill well to provide are fraught with risk.
Furthermore, if an infill well is brought
into operation at an inappropriate time or location, it may produce
hydrocarbons from outside the bypass
region to the detriment of producing through the production wells. To date,
known methods for
determining the production capabilities of an infill well are based on overly
simplified models that
assume gravity is the dominant mechanism driving well. Relying on these known
methods can result in
inefficiently using limited resources to drill an infill well.
SUMMARY
10005] Some implementations of the present disclosure relate to a process
for determining a
production capability of an infill well. This process comprises the steps of:
determining a rate of steam
chamber growth of adjacent steam chambers that are proximal the infill well;
determining a location of
the adjacent steam chambers relative to the infill well; and determining a
hydrocarbon production
capability over time for a bypass area that is in fluid communication with the
infill well based upon at
least the assessments of steps (a) and (b). The infill well may be an existing
infill well or a proposed
infill well.
[0006] Some implementations of the present disclosure relate to a process
for infill well planning.
This process comprises the steps of: determining a pressure drive by comparing
a steam chamber pressure
to a pressure within the infill well; determining a gravity drive; summing the
pressure drive and the
gravity drive to determine a total drive to determine a hydrocarbon production
capability of the infill
well; and determining when to drill the infill well based upon the calculated
hydrocarbon production
capability of the infill well.
[0007] Some implementations of the present disclosure relate to a process
of using field data to
determine hydrocarbon production rates within an infill well. This process
comprises the steps of:
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collecting field-based temperature data from one or more observation wells
that are positioned proximate
the infill; creating a temperature log based upon the collected field-based
temperature data; determining
an initial chamber-distance based upon the temperature log; determining a
steam-interface velocity based
upon the collected field-based temperature data; and determining an optimal
time and location for
producing hydrocarbons with the infill well based on the initial chamber-
distance and the steam-interface
velocity.
[0008] Without being bound by any particular theory, it is postulated
that by accounting for a
pressure differential between inside the infill well and the steam chambers
adjacent the bypass region,
the production capabilities of an infill well can be more accurately and/or
more efficiently determined as
compared to known methods. Furthermore, incorporating captured field-data can
account for the
position and the growth rate of the steam chambers that are adjacent the
targeted bypass regions, which
may further enhance the accuracy and/or efficiency of determining the
production capabilities of the
infill well. With a more accurate understanding of the infill well production
capabilities, one can be
better determine if the infill well can support the resources required to
drill the infill well. Furthermore,
if an infill well's production capabilities can support the resource use, an
optimal infill well configuration
can be designed to maximize the infill well's production. In this disclosure,
an "optimal infill well
configuration" refers to when and where to drill an infill well and the
operational characteristics of the
infill well in order to maximize hydrocarbon recovery from the bypass region.
The optimal infill well
configuration may also minimize production of hydrocarbons from outside of the
bypass region, such as
hydrocarbons within the steam chamber.
BRIEF DESCRIPTION OF THE DRAWINGS
[0009] These and other features of the present disclosure will become
more apparent in the
following detailed description in which reference is made to the appended
drawings, which illustrate by
way of example only:
[0010] FIG. 1 is an isometric view of a schematic of a first vertical
pair of wellbores that are
laterally spaced from a second pair of wellbores and an infill well
therebetween;
[0011] FIG. 2 is a front-elevation view of a first steam chamber that is
laterally spaced from a
second steam chamber with an infill well therebetween, wherein FIG. 2A shows a
first size of the first
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and second steam chambers and FIG. 2B shows a second, larger size of the first
and second steam
chambers;
[0012] FIG. 3 is a front-elevation view of a theoretical bypass region
adjacent an infill well at a
first point in time and a second, later point in time;
[0013] FIG. 4 is a line graph that shows true vertical depth (TVD) of an
infill well, a region that
defines a top of a pay zone, a region that defines a bottom of the pay zone, a
region that defines a bottom
of a steam chamber and the temperature within the infill well;
100141 FIG. 5 is a schematic that shows the relationship between the
growth rate of one or more
adjacent steam chambers and the distance of the one or more adjacent steam
chambers from an infill
well, and how this relationship may impact production of hydrocarbons through
the infill well;
[0015] FIG. 6 is a schematic that shows a framework for matching field
captured data with
parameters that are used in predictive modelling of hydrocarbon production
through an infill well;
[0016] FIG. 7 is schematic that shows a model that integration for
calculating production at the
infill well;
[0017] FIG. 8 is a line graph that shows the relationship between the
viscosity of hydrocarbons
within the bypass region and temperature;
[0018] FIG. 9 is a line graph that shows cumulative hydrocarbon
production from a SAGD
operation, a predicted rate of hydrocarbon production from an infill well, and
the actual rate of
hydrocarbon production from the infill well; and
[0019] FIG. 10 shows two line graphs, wherein FIG. 10A is a line graph of
a calculated
hydrocarbon production rate compared with an actual hydrocarbon production
rate over time and FIG.
10B is a line graph of a calculated hydrocarbon production compared with an
actual hydrocarbon
production rate over time and that compensates for a pressure differential
between the infill well one or
more production wellbores.
DETAILED DESCRIPTION
100201 Implementations of the present disclosure relate to a process for
deteimining a
hydrocarbon production capability of an infill well. The process includes the
steps of: assessing a
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pressure difference between adjacent steam chambers and within the infill well
and assessing the steam
chamber growth velocity based upon data captured from the field, wherein the
data captured from the
field may comprise the location of the adjacent steam chambers relative to the
infill and temperature
data.
[0021] Implementations of the present disclosure relate to a process that
may provide an operator
a better understanding of how adjacent steam chambers are growing and then
using that understanding
to optimize the operational characteristics of the infill well. For example,
the process may be used to
inform an operator about a predicted growth of adjacent steam chambers and
then the operator can use
that information for determining one or more of the following: if the
production capabilities of an infill
well can support a decision to use the resources required to drill and operate
the infill well; where to drill
one or more infill wells relative to a pair of adjacent steam chambers; when
to drill one or more infill
wells based upon a predicted growth of the adjacent steam chambers; a length
of one or more infill wells;
a cross-sectional area of one or more infill wells; a desired pressure within
one or more steam injector
wells to substantially balance production of hydrocarbons through one or more
production wells with
production through one or more infill wells; and the operational parameters of
an artificial lift system
within one or more infill wells.
[0022] Implementations of the present disclosure may also allow an
operator to calibrate for or
adjust for meaningful production and reservoir engineering values such as:
skin loss and/or wellbore
loss.
100231 Implementations of the present disclosure relate to a process for
predicting hydrocarbon
production capabilities of an infill well by assessing a pressure differential
between one or more steam
chambers and an adjacent infill well. In some implementations of the present
disclosure, the sometimes
erratic production of hydrocarbons via an infill well can be more accurately
predicted by accounting for
the flowing bottom hole pressure (FBHP). The FBHP is the pressure within the
infill well when
hydrocarbons are being produced therethrough. The FBHP can be determined by
the operating
parameters of the artificial lift system within the infill well.
[0024] Some implementations of the present disclosure relate to a process
for predicting
hydrocarbon production through an infill well by accounting for captured field-
data. Some non-limiting
examples of captured field-data that may be useful include, but are not
limited to: seismic data;
temperature and/or pressure data of the geological formation and the pay zone
therein; temperature and/or
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pressure data within the production well; and historical hydrocarbon
production data for a given steam
chamber or steam chambers. The captured field-data may allow an operator to
generate a velocity map
of the steam chambers within a given pay zone. The captured field-data may
also allow an operator to
understand the thermal gradient at every point within a model of the bypass
region to better understand
the thermal properties of the bypass region over time.
[0025] The seismic data may assist an operator with determining the
location of a bottom region
of one or more steam chambers and the location of the infill well. The seismic
data may also provide
information that relates to the position of a pay zone and, if already
steamed, the position, shape and size
of the steam chamber within the pay zone. Temperature and/or data that is
captured by one or more
observation wells within the geological formation and the pay zone therein can
provide information as
to how much of a pay zone has been accessed by the steam. This observational-
well data allows an
operator to better understand a sweep efficiency of a steam chamber and the
velocity at which the steam
chamber is growing. The observation well temperature data also may allow an
operator to detect if there
is a leak of steam into or past the overburden that is above the pay zone,
which can become a safety
concern. In particular, the pressure data obtained from observational wells
allows an operator to
understand when an edge of the steam chamber is approaching the observational
well.
[0026] The implementations of the present disclosure relate to a process
for optimizing the use
of infill wells during thermal recovery operations for the production of heavy
hydrocarbons. Such an
optimization provides not only economic benefits but also environmental
benefits. For example, the
implementations of the present disclosure may enhance heavy hydrocarbon
production by an infill well
from the bypass region while minimizing infill well production of hydrocarbons
from the steam chamber.
Furthermore, the production capability of an infill well can be used to decide
if an infill well can support
the resources that are required for drilling and operating the infill well.
The production capability of an
infill well can also be used to set schedules for drilling and operating new
infill wells. Implementations
of the present disclosure may provide an operator to more accurate forecast
information and that can
allow the operator to better align capital cost outlays for an infill well,
with production output and
downstream hydrocarbon processing capabilities. In other words, the timing of
production can be
matched with times when processing capabilities are not overwhelmed or
otherwise decreased.
[0027] From an environmental perspective, the implementations of the
present disclosure relate
to a process for improving the efficiency of hydrocarbon production from a
bypass region whereby a
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greater amount of hydrocarbons can be mobilized with a lower steam requirement
and, therefore, less
water is used and less energy required for steam generation.
[0028] Unless defined otherwise, all technical and scientific terms used
herein have the same
meaning as commonly understood by one of ordinary skill in the art to which
this disclosure belongs.
[0029] As used herein, the term "about" refers to an approximately +/-10%
variation from a given
value. It is to be understood that such a variation is always included in any
given value provided herein,
whether or not it is specifically referred to.
[0030] As used herein, the term "artificial lift system" refers to
various mechanisms for actively
or passively drawing fluids into an infill well and for lifting said fluids to
the surface. Applicable types
of artificial lift systems include, but are not limited to: a submersible
pump, an electrical submersible
pump, a progressive capacity pump, a gas lift system, sucker rods, plunger
lifts and using high steam
chamber pressures to drive fluids to the surface.
100311 As used herein, the phrase "operational characteristics of the
infill well" refers to at least
one of the following: operational parameters of an artificial lift system
within the infill well, the type of
artificial lift system, the fluid moving capacity and rate of the artificial
lift system, the position of the
infill well within the bypass region, a length of the infill wellbore, a cross-
sectional area of the infill
wellbore or combinations thereof.
[0032] As used herein, the term "optimal infill well configuration"
refers to when and where to
drill an infill well and the operational characteristics of the infill well in
order to maximize hydrocarbon
recovery from the bypass region.
[0033] Implementations of the present disclosure will now be described by
reference to FIG. 1
to FIG. 10.
100341 FIG. 1 shows a typical steam assisted gravity drainage (SAGD) well
arrangement that
includes a first pair of substantially vertically spaced apart wells with a
first injection well 10A and a
first production well 12A. FIG. 1 also shows a second pair of substantially
vertically spaced apart wells
that includes a second injection well 10B and a second production well 12B.
The first pair of wells 10A,
12A are laterally spaced from the second pair of wells 10B, 12B. Both of the
first pair of wells 10A,
12A and the second pair of wells 10B, 12B are shown has having a substantially
vertical portion 3 and a
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substantially horizontal portion 5. The substantially vertical portion 3
extends from surface (not shown)
to approximately a depth below surface where a pay zone 6 of a geological
formation is located. The
substantially horizontal portion 5 extends substantially through or proximal
to the pay zone 6.
[0035] Positioned between the first pair of wells 10A, 12A and the second
pair of wells 10B, 12B
is an infill well 100. The infill well 100 is also shown as being within a
bypass region 102 that is defined
between the first pair of wells 10A, 12A and the second pair of wells 10B,
12B. While FIG. 1 shows all
of these wells as having both a substantially vertical section 3 and a
substantially horizontal section 5. It
is understood by those skilled in the art that these wells may also define a
bypass region 102 that is
substantially vertical, or both substantially vertical and substantially
horizontal rather than just being
substantially horizontal. It is also understood by one skilled in the art that
implementations of the present
disclosure are not limited to just SAGD or other forms of thermal mobilization
techniques. For example,
implementations of the present disclosure can also be useful with other
techniques for hydrocarbon
mobilization including, but not limited to: cyclic steam-stimulation, solvent
injection, non-condensable
gas injection, steam flooding, surfactant injection, combinations thereof or
any other hydrocarbon
mobilization technique that creates a bypass region with hydrocarbons therein
that can be produced by
an infill well.
[0036] The infill well 100 can collect and produce to surface
hydrocarbons within the bypass
region 102 that are mobilized by steam that is injected into the pay zone of
the geological formation by
one or both of the injector wells 10A, 10B.
[0037] FIG. 2 shows a first steam chamber 14A and a second steam chamber
14B. The first
steam chamber 14A is formed during and after steam injection from the first
injection well 10A. The
second steam chamber 14B is similarly formed during and after steam injection
from the second injection
well 10B. As the steam within the steam chambers 14A, 14B moves away from the
injection wells 10A,
10B, the steam transfers heat into the viscous and heavy hydrocarbons within
the pay zone 6. This heat
transfer mobilizes the hydrocarbons by decreasing hydrocarbon viscosity. The
heat transfer also causes
the steam to phase shift into liquid water. Under the force of gravity, the
liquid water and the mobilized
hydrocarbons drain into a liquid pool 16A, 16B of each respective steam
chamber 14A, 14B. The
production wells 12A, 12B are often submerged within their respective liquid
pools 16A, 16B so that
steam is not drawn into the production wells 12A, 12B, which can cause damage
to the well
infrastructure. The production wells 12A, 12B may also include some form of
artificial lift system (not
shown) for producing the collected fluids up to the surface. However, because
the artificial lift systems
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are submerged within the liquid pools 16A, 16B, the artificial lift systems
within the production wells
12A, 12B have a negligible effect on driving the mobilized hydrocarbons into
the liquid pools 16A, 16B.
In effect, the liquid pools 16A, 16B act as a buffer against the pressure
generated by the injection wells
10A, 10B and/or the artificial lift systems of the production wells 12A, 12B
from driving the collection
and production of mobilized hydrocarbons within the steam chambers 14A, 14B.
Current approaches
for determining production capabilities of the production wells 12A, 12B are
based upon the influence
of gravity on the mobilized hydrocarbons.
100381 The bypass region 102 is defined by the adjacent lateral edges of
the steam chambers 14A,
14B. The heat within the steam can also heat and mobilize viscous and heavy
hydrocarbons within the
bypass region 102. As shown in FIG. 2B, the bypass region 102 can be divided
into two sub-regions, an
infill region 102A and a cellar region 102B. A dashed line is shown in FIG. 2B
as indicating a general
area below the bottom edges of the steam chambers 14A, 14B, this dashed line
is a general indication of
where the infill area 102A stops and the cellar area 102B begins. It is
generally understood that any
mobilized hydrocarbons within the bypass region 102, and in particular
mobilized hydrocarbons within
the cellar region 102B will only be produced by the infill well 100.
100391 The infill well 100 also includes an artificial lift system (not
shown) for producing
collected mobilized hydrocarbons to the surface. In contrast to the artificial
lift systems of the production
wells 12A, 12B, the artificial lift system of the infill well 100 creates a
pressure gradient within the
bypass region 102 that drives mobilized hydrocarbons into the infill well 100.
The pressure gradient is
determined by the difference in pressure between the pressure within the steam
chamber and the pressure
within the infill well itself, which may be referred to herein as the fluid
bottom hole pressure (FBHP).
[0040] FIG. 2B also shows the growth of the steam chambers 14A, 14B. For
example, the double
sided arrows 14C and 14D show the expansion of the respective steam chambers
14A, 14B over time.
As the steam chambers 14A, 14B grow, the bypass region 102 shrinks because the
adjacent lateral edges
of the steam chambers 14A, 14B are moving closer towards each other. As such,
implementations of the
present disclosure are directed at processes for modeling growth of the steam
chambers 14A, 14B and
determining the production capability of the infill well 100 in an effort to
best determine if an infill well
100 is going to produce sufficient hydrocarbons to support the resources
required for drilling and
operating the infill well 100. Furthermore, if an infill well 100 is going to
be drilled, determining the
production capability of the infill well 100 can be used to design the infill
well dimensions, position and
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operating parameters to optimize infill well 100 production of hydrocarbons
without interfering with
production well 12A, 12B production of hydrocarbons.
[0041] FIG. 3 shows a schematic where the bypass region 102 is modelled
as a semi-circle. The
double arrow 102C shows the shrinking of the bypass region 102 over time that
is due to the growth of
the steam chambers 14A, 14B. By knowing Rtninai and Ux, an initial step of a
process according to the
present disclosure is to calculate the temperature at each point within the
semi-circle. Such a temperature
can be determined using the equation of Formula 1:
4 = Rinitial r ¨ U. t
[1],
wherein:
4 is a distance from the moving steam interface
Rininal is the radial distance from infill well to the steam chamber at the
time of drilling;
r is the radial distance between the center of infill well and the steam
chamber at a given time t;
U, is the velocity of the steam interface; and
t is the elapsed time after the infill well is drilled and put on production.
[0042] Another step of the process is to determine a radius of the semi-
circle based upon the
difference between the bottom edge of the steam chamber 14A, 14B and the
location of the infill well
100. FIG. 4 shows one example of seismic data that provides true vertical
depth measurements (TVD in
meters) of a top edge 200 of a pay zone 6, the bottom edge 202 of the pay zone
6, the bottom edge 204
of one of the steam chambers 14A, 14B and the position 206 of the infill well
100. FIG. 4 also shows
temperature data 208 that was acquired by a temperature sensor within the
infill well 100.
[0043] Another step in the process is to determine the production rate
within the infill well 100
as a function of how fast one or both of the steam chambers 14A, 14B are
growing and how far the steam
chambers 14A, 14B are from the infill well 100. FIG. 5 is a schematic that
shows the factors used for
assessing the rate at which the steam chamber 14A, 14B is growing.
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[0044] FIG. 6 is a schematic that represents a framework 300 for
determining the production
capability of an infill well 100 using data captured from the field. Data 302
from various observation
wells that are drilled vertically throughout the geological formation and the
pay zone 6 is used to generate
a U. map 304. The U. map shows the rate at which one or more steam chambers
are growing within a
pay zone 6. Temperature data 306 from the same or different observation wells
as the source of data 302
= is used in two fashions. In a first fashion the temperature data 306 is
used in a U. calculation 310, which
together with the U. map 304 establish the rate at which the steam chambers
14A, 14B are growing. This
rate of growth may also be referred to herein as the steam interface velocity
U.. In a second fashion, the
temperature data 306 is used to calculate the steam temperature (Tst) 311. The
Tst 311 can be used as a
quality control assessment 313 of the U. calculation 310 and vice versa. The
temperature data 306 also
provides a vertical thermal profile of a given observation well. That vertical
thermal profile can be used
to confirm further temperature data 308 that is captured from temperature
sensors within the production
wells 12A, 12B. This further temperature data 308 is used to establish a well
temperature log 314 and
to perform an Rmt calculation 316 to determine Rint 317, which is referred to
as an initial chamber-distance
between the steam chambers 14A, 14B (which is the same as the outer edge of
the bypass region 102)
and the infill well 100. The Tst 311 can also be used to supplement and/or
quality control the accuracy
of the temperature log 314. Seismic data 318 may also be used as a quality
control assessment 320 of the
Rim 317 value and vice versa. The framework 300 uses data captured from the
field to generate and
quality control either or both of the U. 322 of the steam chambers 14A, 14B
and the Rint 317 between
the steam chambers 14A, 14B and inside the infill well 100.
[0045] Together the U. 322 and the Rim 317 can be used in an equation
(described further below)
to determine the hydrocarbon production capability 324 of the infill well 100,
whether an existing infill
well 100 or a proposed infill well. The framework 300 can also compare the
hydrocarbon capability 324
of the infill well 100 with a historical production 328 of the same infill
well (100) if the infill well 100
is already drilled and producing hydrocarbons. Taking production history
matching into consideration
may increase the accuracy and/or efficacy of the determinations made using the
implementations of the
present disclosure. The infill FBHP 326 can also be assessed in the model 324
to increase the accuracy
and/or efficacy thereof.
[0046] FIG. 7 is a schematic representation of how integration can be
used to calculate production
capability of the infill well 100 over time.
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[0047] FIG. 8 is a line graph that shows an example of hydrocarbon
viscosity as a function of
time measured in samples taken from four different depths within the bypass
region (103.7 meters (m),
113.4 m, 105.9 m and 128 m). FIG. 8 also shows an average viscosity as a
function of time for each of
the four depths.
[0048] Formula 2 provides an equation for determining a hydrocarbon
production capability of
the infill well 100.
[0049] As set out in formula 2:
dq = dq, + dq2
[2]
wherein:
q is the total rate produced from infill;
qi is the flow rate due to the pressure gradient between the infill well and
the steam chamber(s), which
is also referred to as the pressure drive; and
q2 is the flow rate due to gravity, which is also referred to as the gravity
drive.
[0050] As set out in formula 3:
kkr (a
dq=. P ¨ ¨+pogsinOjdA
[3]
wherein:
dq is the unit volume of the reservoir to be integrated;
k is the absolute permeability of the reservoir;
kro is the oil relative permeability;
1.1. is the oil viscosity;
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aP
¨ is the pressure gradient in a radial direction;
ar
pc, is the oil density;
g is the acceleration due to gravity (approximately 9.81 m/s2);
0 is the flow angle (describing the oil bank geometry in the bypassed region);
and
dA is the cross sectional area of the unit volume dq .
[0051] As set out in formula 4:
nkkroL(Pch ¨ Pw )
c11
[tõ exp[m Ux (R1 Uxt) El rwm UN Ei (Rint Urt)m Ux ]+s}
KThermal KThermal KThermal
[4]
wherein:
q1 is as defined above;
k is as defined above;
kro is as defined above;
L is the length of the infill well;
Pa is the pressure of the steam chamber;
is the pressure within the infill well, which is also referred to as FBHP;
[1st is the oil viscosity at steam temperature;
m is the Butler dimensionless viscosity coefficient;
Ux is as defined above;
a is the thermal conductivity of the reservoir;
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is Rinthai, as defined above;
Et is the exponential integral;
rw is the wellbore radius; and
S is the wellbore skin.
[0052] As set out in formula 5:
kk
rwLexp
C12 = 2-2-Prog[mU ¨Uxt)]
1-tst
151
wherein:
(12 is as defined above;
k is as defined above;
km is as defined above;
list is as defined above;
p is as defined above;
g is as defined above;
rw is as defined above;
L is as defined above;
m is as defined above;
Ux is as defined above;
a is as defined above; and
4 is as defined above.
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A8141029CADIV
[0053] As set out in formula 6:
0 = st Tst Trm
T ¨
[6]
wherein:
1st is the oil viscosity at steam temperature;
. is the calculated oil viscosity;
T is the temperature at which is p.-'o calculated;
Tr is the reservoir temperature;
Tg is the saturation temperature of steam at the steam chamber pressure; and
m is as defined above.
[0054] FIG. 9 shows a line graph that depicts relative hydrocarbon
production capability of an
infill well 100 as a rate 400 (m3/day) overtime, actual hydrocarbon production
rates 402 over time
recorded at the infill well 100, a forecast of cumulative hydrocarbon
production 404 from the infill well
100 and actual cumulative hydrocarbon production 406. The hydrocarbon
production capability rate 400
was calculated based upon one or more of the formula above. Without being
bound by any particular
theory, the rate 400 decreases over time due to the shrinking of the bypass
area 102.
[0055] FIG. 10 shows a line graph that depicts another rate 408 of
hydrocarbon production
capability of an infill well 100 and an actual hydrocarbon production rate 410
recorded at the infill well
100. The forecast rate 408 was modeled based upon a constant pressure and it
is clear that the forecast
rate 408 is different from the actual rates 410, particularly through the
first few data points. However,
the FBHP data can be back calculated based upon the actual hydrocarbon
production rate 410. The back
calculated FBHP data was used to calculate an adjusted rate 408A of
hydrocarbon production capability
of the infill well 100 and the adjusted rate 408A and the actual rate 410 are
more closely aligned (see
FIG. 10B versus FIG.10A).
CA 3071806 2020-02-10
