Note: Descriptions are shown in the official language in which they were submitted.
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DESCRIPTION:
CROSS REFERENCE TO RELATED APPLICATIONS
This application claims priority from United States (US) Disclosure Document
589,546 by Dr. Henry Crichlow filed on 11 /07/2005 and United States
Provisional US Patent 60/763,844 filed on 2/1 /2006 by Dr. Henry Crichlow and
Utility patent application 1 1/279,681 filed 4/13/2006.
INTRODUCTION:
This invention relates generally to a new technology application and a new
type
of oil well for recovery of hydrocarbons from subterranean oil bearing
formations.
This invention is related to prior filings by the same applicant, pertaining
to the
overall recovery of hydrocarbons from subterranean oil formations. The
technology involves the novel use and application of equipment and techniques
in which horizontal wells are drilled from the surface down to and across an
oil
bearing formation and back up to the surface, in a manner similar to that of
drilling under a river crossing when laying pipelines across country. This new
type of horizontal well is called a UniwellT" because it has two surface
wellheads
one at each end of the axis of the horizontal system. Either wellhead can be
used for either injection or production as needed by the operator. In
addition,
this invention utilizes a collection cavity drilled into and below the
horizontal
well(s) to form a collection site for the produced oil.
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The technology is a new application using some elements of an existing
drilling
technology, which have hitherto been used only in horizontal pipeline crossing
installations and some technology elements, which have been used in
conventional oil well drilling. This novel completion technique uses injection
and production perforations in the same wellbore, separated by a moveable
wellbore packer.
FIELD OF INVENTION:
THIS INVENTION is a unique new approach for heavy oil recovery. The invention
is particularly suited to making heavy oil formations, oil shales and tar
sands
producible by a single wellbore system drilled using a specialized form of
horizontal directional drilling. The invention however is not limited to
recovery
of heavy oils only; it can be used for many oil recovery processes such as tar
sands and oil shale. In this application tar sands also means oil sands and
each
term is mutually interchangeable.
With this invention, the operator drills a new type of well that has all the
operational benefits of a horizontal well and in addition this drilling can be
implemented either by using modified equipment that is readily available in
allied industries such as pipeline laying or by modifying existing oil well
drilling
rigs. This novel drilling approach effectively lowers costs and increases
efficiencies because it can utilize available equipment to drill wells with
greater
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productive capacity. This approach allows wells to be drilled over large
lateral
distances, up to as much as 5,000 feet in shallow depth oilfields. At greater
depths, the lateral extension is limited by the rig capability and mechanical
limitations of torque and drag in the drilling process. The reaming process to
drill the collection cavity is done with conventional under-reaming tools
which
can easily construct a cavity up to 96 inches in diameter in the hydrocarbon
formation. With this innovation, which involves in part, the injection and
production from the same well, increased levels of oil recovery are achievable
in
field practice.
BACKGROUND OF THE INVENTION
Introduction:
Heavy hydrocarbons in the form of petroleum deposits are distributed
worldwide and the heavy oil reserves are measured in the hundreds of billions
of recoverable barrels. Because of the relatively high oil viscosity, which
can
exceed 106 cp, these crude deposits are essentially immobile and cannot be
easily recovered by conventional primary and secondary means. The only
economically viable means of oil recovery is by the addition of heat to the
oil
deposit, which significantly decreases the viscosity of the oil by several
orders
of magnitude and allows the oil to flow from the formation into the producing
welibore. Today, the steam injection can be done in a continuous fashion or
intermittently as in the so-called "huff and puff' or cyclic steam process.
Oil
recovery by steam injection involves a combination of physical processes
including, gravity drainage, steam drive and steam drag to move the heated oil
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from the oil zone into the producing wellbore.
The most significant oil recovery problem with heavy oil, tar sands and
similar
hydrocarbonaceous material is the extremely high viscosity of the native
hydrocarbons. The viscosity ranges from 10,000 cp at the low end of the range
to 5,000,000 cp at reservoir conditions. The viscosity of steam at injection
conditions is about 0.020 cp. Assuming similar rock permeability to both
phases steam and oil, then the viscosity ratio provides a good measure of the
flow transmissibility of the formation to each phase. Under the same pressure
gradient, gaseous steam can therefore flow from 500,000 to 250,000,000
times easier through the material than the oil at reservoir conditions.
Because
of this viscosity ratio, it is imperative and critical to any recovery
application
that the steam be confined or limited to an area of the reservoir by a seal.
This
seal can be physical, hydraulic or pneumatic and essentially must provide a
physical situation which guarantees no-flow of any fluid across an interface.
This can be implemented by several means. Without this "barrier" the steam
will bypass, overrun, circumvent, detour around the cold viscous formation and
move to the producer wellbore. This invention addresses and resolves this
major obstructive element in heavy oil recovery.
Horizontal wells have played a prominent part in recovery of oil. These wells
can be as much as 4 times as expensive to drill as conventional vertical
wells,
but the increased expenses are offset by the increases in rates of oil
production
and faster economic returns. Several patents have described various
approaches to using horizontal wellbores. The need for horizontal wells
requires a more efficient economical and easily deployable system for
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developing and drilling these wells. This novel utilization proposed herein
addresses the needs and teaches a process of horizontal well drilling that is
more easily implemented, allows a larger portion of the reservoir to be
exposed
and allows more oil recovery to occur.
By implementing the new processes which are taught in this application by this
invention the oilfield operator can see improved performance, lower costs,
better oilfield management, and allow for efficient and orderly development of
petroleum resources.
Improvements have been made in enhancing the contact of the steam with the
native heavy oil by the introduction of horizontal well technology, which
allows
greater recovery than with the customary vertical wells. This current
invention
provides a further extension of the horizontal technology in which a novel
drilling methodology is applied to the drilling effort to allow wells of much
larger lateral extent, potentially larger diameters and thereby more efficient
recovery systems.
Prior Art:
Various methods and processes have been disclosed for recovery of oil and gas
by using horizontal wells. There have been various approaches utilized with
vertical wellbores, to heat the reservoirs by injection of fluids and also to
create
a combustion front in the reservoir to displace the insitu oil from the
injection
wellbore to the production wellbore.
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US Patent 3,986,557 claims a method using a horizontal well with two
wellheads that can inject steam into a tar sand formation mobilizing the tar
in
the sands. In this patent, during the injection of the steam it is hoped that
the
steam will enter the formation and not continue directly down the open
wellbore and back to the surface of the opposite wellhead. It is technically
difficult to visualize the steam entering a cold highly viscous formation
while a
completely open wellbore is available for fluid flow away from the formation.
Furthermore, 3,986,557 teaches that the steam is simultaneously injected
through perforations into the cold bitumen formation while hot oil is flowing
through the same perforations, in the opposite direction through the rock pore
structure, against the invading high pressure steam. This situation is not
only
physically impossible but it thermodynamically impossible for the hot fluid to
flow "against the pressure gradient".
US Patent 3,994,341 teaches a vertical closed loop system inside the wellbore
tubulars in which a vertical wellbore is used to generate a vertical
circulation of
hot fluids which heat the wellbore and nearby formation. Hot fluids and drive
fluids are injected into upper perforations which allow the driven oil to be
produced from the bottom of the formation after being driven towards the
bottom by the drive fluid.
US Patent 4,034,812 describes a cyclic injection process where a single
wellbore is drilled into an unconsolidated mineral formation and steam is
injected into the formation for a period of time to heat the viscous petroleum
in
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the vicinity of the well and causing the unconsolidated mineral sand grains to
settle to the bottom of the heated zone in a cavity and the oil to move to the
top of the zone.
US Patent 4,037,658 teaches the use of two vertical wells connected by a cased
horizontal shaft or "hole" with a flange in the vertical well. This type of
downhole flange connection is extremely difficult if not impossible to
implement in current oilfield practice. Two types of fluids are used in this
patent, one inside the horizontal shaft as a heater fluid and one in the
formation as a drive fluid. Both fluids are injected either intermittently of
simultaneously from the surface wellheads.
Butler et al in 4,116,275 use a single horizontal wellbore with multiple
tubular
strings internal to the largest wellbore for steam recovery of oil. Steam was
injected via the annulus and after a soak period the oil is produced from the
inner tubing strings.
US Patent 4,445,574 teaches the drilling of a single well with two wellheads.
This well is perforated in the horizontal section and a working fluid is
injected
into the wellbore to produce a mixture of reservoir oil and injected working
fluid. Similar to the 3,986,557 patent it is difficult from a hydraulic point
of
view to visualize and contemplate the working fluid entering the formation
while an open wellbore is available for fluid flow horizontally and vertically
out
the distal end of this wellbore.
US Patent 4,532,986 teaches an extremely complex dual well system including
a horizontal wellbore and a connecting vertical wellbore which is drilled to
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intersect the horizontal well. The vertical well contains a massively complex
moveable diverter system with cables and pulleys attached to the two separate
wellheads to allow the injection of steam. This system is used to inject steam
from the vertical wellhead into the horizontal wellbore cyclically and
sequentially while the oil is produced from the wellhead at the surface end of
the horizontal well.
Huang in US Patent 4,700,779 describes a plurality of parallel horizontal
wells
used in steam recovery in which steam is injected into the odd numbered wells
and oil is produced in the even numbered wells. Fluid displacement in the
reservoir occurs in a planar fashion.
US Patent 5,167,280 teaches single concentric horizontal wellbores in the
hydrocarbon formation into which a diffusible solvent is injected from the
distal
end to effect production of lowered viscosity oil backwards at the distal end
of
the concentric wellbore annulus.
US Patent 5,215,149 by Lu, uses a single wellbore with concentric injection
and
production tubular strings in which the injection is performed through the
annulus and production occurs in the inner tubular string, which is separated
by a packer. This packer limits the movement of the injected fluids laterally
along the axis of the wellbores. In this invention the perforations are made
only
on the top portion of the annular region of the horizontal well. Similarly the
production zone beyond the packer is made on the upper surface only of the
annular region. These perforated zones are fixed at the time of well
completion
and remain the same throughout the life of the oil recovery process.
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Balton in 5,402,851 teaches a method wherein multiple horizontal wells are
drilled to intersect or terminate in close proximity a vertical wellbore. The
vertical wellbore is used to actually produce the reservoir fluids. The
horizontal
wellbore provides the conduits, which direct the fiuids to the vertical
producing
welibore.
US Patent 5,626,193 by Nzekwu et al disclose a single horizontal well with
multiple tubing elements inside the major wellbore. This horizontal well is
used
to provide gravity drainage in a steam assisted heavy oil recovery process.
This
invention allows a central injector tube to inject steam and then the heated
produced fluids are produced in a backwards direction through the annular
region of the same wellbore beginning at the farthest or distal end of the
horizontal wellbore. The oil is then lifted by a pump. This invention shows a
process where the input and output elements are the same single wellbore at
the surface.
US Patent 5,655,605 attempts to use two wellbores sequentially drilled from
the
surface some distance apart and then to have these horizontal wellbore
segments intersect each other to form a continuous wellbore with two surface
wellheads. This technology, while theoretically possible is operationally
difficult
to hit such a small underground target, i.e the axial cross-section of a
typical
8-inch wellbore using a horizontal penetrating drill bit. It further teaches
the
use of the horizontal section of these intersecting wellbores to collect oil
produced from the formation through which the horizontal section penetrates.
Oil production from the native formation is driven by an induced pressure drop
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in the collection zone by a set of valves or a pumping system which is
designed
into the internal concentric tubing of this invention. The 5,655,605 patent
also
describes a heating mechanism to lower the viscosity of the produced oil
inside
the collection horizontal section by circulating steam or other fluid through
an
additional central tubing located inside the horizontal section. At no time
does
the steam or other hot fluid actually contact the oil formation where
viscosity
lowering by sensible and latent heat transfer is needed to allow oil
production
to occur.
US Patent 6,708,764 provides a description of an undulating well bore. The
undulating well bore includes at least one inclining portion drilled through
the
subterranean zone at an inclination sloping toward an upper boundary of the
single layer of subterranean deposits and at least one declining portion
drilled
through the subterranean zone at a declination sloping toward a lower
boundary of the single layer of subterranean deposits. This embodiment looks
like a waveform situated in the rock formation.
US Patent 6,725,922 utilizes a plurality of horizontal wells to drain a
formation
in which a second set of horizontal wells are drilled from and connected to
the
first group of horizontal wells. These wells form a dendritic pattern
arrangement to drain the oil formation.
US Patent 6,729,394 proposes a method of producing from a subterranean
formation through a network of separate wellbores located within the formation
in which one or more of these wells is a horizontal wellbore, however not
intersecting the other well but in fluid contact through the reservoir
formation
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with the other well or wells.
Patent 6,948,563 illustrates that increases in permeability may result from a
reduction of mass of the heated portion due to vaporization of water, removal
of hydrocarbons, and/or creation of fractures. In this manner, fluids may more
easily flow through the heated portion.
US Patents 6,951,247, 6,929,067, 6,923,257, 6,918,443, 6,932,155,
6,929,067, 6,902,004, 6,880,633, 20050051327, 20040211569 by various
inventors. and assigned to Shell Oil Company have provided a very exhaustive
analysis of the oil shale recovery process using a plurality of downhole
heaters
in various configurations. These patents utilize a massive heat source to
process and pyrolize the oil shale insitu and then to produce the oil shale
products by a myriad of wellbore configurations. These patents teach a variety
of combustors with different geometric shapes one of which is a horizontal
combustor system which has two entry points on the surface of the ground,
however the hydrocarbon production mechanism is considerably different from
those proposed herein by this subject invention.
US Patent 6,953,087 by Shell, shows that heating of the hydrocarbon formation
increases rock permeability and porosity. This heating also decreases water
saturation by vaporizing the interstitial water. The combination of these
changes increases the fluid transmissibility of the formation rock in the
heated
region.
Dynatec in Ref. 3 teaches in a coal bed degassing operation the use of a pair
of
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horizontal wellbores connected to a central vertical wellbore which is used to
drain gas from coal bed methane formations. The Dynatec methodology is a
passive procedure in which gas is drained and where the wellbores behave as
extended lateral fractures in which gas flowed into the central zone where gas
and water commingled before being lifted to the surface. The Dynatec
horizontal wellbores do not appear to extend to and be open to the surface of
ground. In addition, in the Dynatec method there is no displacement
mechanism to move the petroleum fluid as taught in the subject application of
petroleum extraction using horizontal and vertical wellbores.
US Patent application 20050045325 describes a recovery mechanism for heavy
oil hydrocarbons in which a pair of wells is used. A vertical injector well is
horizontally separated from a vertical production well. The hot fluid, steam
or
air is injected into the bottom portion of the injector and is expected to
displace the very viscous immobile oil from the cold reservoir and push this
hot
oil through the cold oil saturated formation eventually to the producer. The
invention expects oil flow to occur by drilling a web or radial channels from
the
injector to the producer. It is inconceivable that viscous cold oil, or even
lower
viscosity hot oil will preferably flow along these channels while extremely
low
viscosity high-pressure steam will flow through the cold formation. Flow
mechanics in porous media dictates that hot, saturated steam will completely
bypass cold viscous oil and the process will be a quick steam recycle process
from injector to producer.
The Society of Petroleum Engineers Ref. 1, SPE paper 20017 teaches a computer
simulation of a displacement process using a concentric wellbore system of
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three wellbore elements and complex packers in which steam is injected in a
vertical wellbore similar to that in the 3994341 patent. Simulated steam
injection occurs through one tubing string and circulates in the wellbore from
just above the bottom packer to the injection perforations near. the top of
the
tar sand. This circulating steam turns the wellbore into a hot pipe which
heats
an annulus of tar sand and provides communication between the steam
injection provides communication between the steam injection perforations
near the top of the tar sand and the fluid production perforations near the
bottom of the tar sand. This process required 7 years to increase oil
production
from 20 BOPD to 70 BOPD.
Paper 37115 describes a single-well technology applied in the oil industry
which uses a dual stream well with tubing and annulus: steam is injected into
the tubing and fluid is produced from the annulus. The tubing is insulated to
reduce heat losses to the annulus. This technology tries to increase the
quality
of steam discharged to the annulus, while avoiding high temperatures and
liquid flashing at the heel of the wellbore.
SPE paper 50429 presents an experimental horizontal well where the horizontal
well technology was used to replace ten vertical injection wells with a single
horizontal well with limited entry. The limited-entry perforations enabled
steam
to be targeted at the cold regions of the reservoir.
SPE paper 50941 presents the "Vapex" process which involves injection of
vaporized hydrocarbon solvents into heavy oil and bitumen reservoirs; the
solvent-diluted oil drains by gravity to a separate and different horizontal
production well or another vertical well.
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SPE paper 53687 shows the production results during the first year of a
thermal
stimulation using dual and parallel horizontal wells using the SAGD technology
in Venezuela.
SPE paper 75137 describes a THAI - 'Toe-to-Heel Air Injection' system
involving a short-distance displacement process, that tries to achieve high
recovery efficiency by virtue of its stable operation and ability to produce
mobilized oil directly into an active section of the horizontal producer well,
just
ahead of the combustion front. Air is injected via a separate vertical or a
separate horizontal wellbore into the formation at the toe end of different
horizontal producer well and the combustion front moves along the axis of the
producer well.
SPE paper 78131 published an engineering analysis of thermal simulation of
wellbore in oil fields in western Canada and California, U.S.A.
SPE paper 92685 describes U-tube well technology in which two separate
wellbores are drilled and then connected to form a single wellbore. The U-tube
system was demonstrated as a means of circumventing hostile surface
conditions by drilling under these physical obstacles.
Reference 4 shows conclusively that the gravity drainage effect is the most
critical factor in oil recovery in heavy oil systems undergoing displacement
by
steam.
Very few of these prior art systems have been used in the industry with any
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success because of their technical complexity, operational difficulties, and
being physically impossible to implement or being extremely uneconomical
systems.
For example, in 3,994,341, this embodiment which although on the surface
resembles the invention herein differs significantly since, the 3,994,341
patent
forms a vertical passage way only by circulating a hot fluid in the wellbore
tubulars to heat the nearby formation, the 3,994,341 patent claims the drive
fluid promotes the flow of the oil by vertical displacement downwards to the
producing perforations at the bottom. The 3,994,341 patent teaches the
production perforations are set at the bottom of the vertical formation, a
distance which can be several hundred feet in real field cases.
First, in this 3,994,341 embodiment, since no control mechanism like a back
pressure system or pressure control system is taught, it is obvious that the
high
pressure drive steam, usually at several hundred psi, will preferentially flow
down the vertical passageway immediately on injection and bypass the cold
formation with its highly viscous crude and extremely low transmissibility.
Secondly, the large distance between the top of the formation and the bottom
of the formation will cause condensation of the drive steam allowing
essentially
hot water to be produced at the bottom with low quality steam, both fluids
being re-circulated back to the surface. In addition, the mechanism to heat
the
near wellbore can only be based on conductive heat transfer through the steel
casing. There is ineffective heat transfer since there is no direct steam
contact
with the formation rock in which latent heat transfer to formation fluids and
rock can occur, this latent heat being the major heat transport system. The
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3,994,341 process is incapable of delivering sufficient heat in a reasonable
time to heat the formation sufficiently to lower the viscosity of the oil,
raise the
porosity and permeability of the formation as taught in the present patent
application.
There is a long felt need in the industry for a means of moving the heated low
viscosity crude oil that has been contacted by the steam in the steam zone to
a
place or location where it can be produced without having to move it through a
cold heavily viscous oil impregnated formation. This problem has continued to
baffle the contemporary and prior art with possibly the only exception being
the SAGD patent which uses two horizontal wells closely juxtaposed in a
vertical
plane. Even this SAGD approach has inherent difficulties in initiating the hot
oil
flow between the two wellbores. Trying to push the hot oil through a cold
formation is an intractable proposition. The subject invention offers a
solution
to this need and provides the mechanism by which the solution can be
implemented using conventional equipment and procedures.
Shortcomings of prior art can be related to a combination of effects. These
include;
(1) the inability of the process to inject the hot fluid into and across the
length of a cold highly viscous oil formation with limited conductivity due to
with oil viscosities in excess of 106 cp.
(2) the viscosity of steam is less than 0.020 cp under the reservoir
conditions which makes the flow of steam through porous media 5,000,000
times easier than cold high viscosity oil of 100,000 cp. This flow ratio is
based
directly on the viscosity ratios.
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(3) the inability of the methods to prevent steam bypass without some
type of seal mechanism, of this extremely highly mobile injected fluid
directly
from the injector source towards the producing sink;
(4) the inability of the method to form and maintain a viable
communication zone from the steam zone or chamber to the producing sink
while preventing bypass and early breakthrough of steam;
(5) the inability of the process to utilize the gravity drainage effects
created by the low density of the hot steam compared to condensed water and
hot oil;
(6) the inability of the process to heat the formation effectively by
physical contact between the steam and the rock formation such that latent
heat, the major source of steam heat energy, can be transferred to the rock
and
hydrocarbons efficiently;
(7) the requirement of long lead times of months to years of hot fluid
injection, before there is any production response of the displaced oil;
(8) finally the use of overly complex equipment of questionable
operational effectiveness to implement the process in the field.
THIS NEW INVENTION provides an improvement in the method whereby the
operator drills a specially designed and under-reamed vertical well to form a
central production cavity; and a plurality of horizontal wells, which are
drilled
from the surface down to the producing formation, and laterally to intersect
the
central cavity. In one embodiment, the lateral wellbore is continued drilling
upwards to the surface to form a uniwellT". In this embodiment, this
continuous uniwellT"' behaves as a single well with two wellheads. The
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additional implementation is the development of a central collection cavity
into
which the hot displaced oil is allowed to drain from the lateral horizontal
wells
in to the central collection cavity. A producing mechanism including pumping
equipment lifts the produced oil from the central cavity to the surface. The
techniques proposed herein use a combination of drilling activities that are
known separately and distinctly in the industry, but have not yet been
utilized
in this integrated manner shown in this new invention.
SUMMARY OF THE INVENTION:
An object of this invention is to provide an improved process for recovery of
heavy oils and similar hydrocarbons from subterranean formations by
exploiting the advantages provided by gravity drainage in the displacement
process of heavy oils in porous formations using steam or combustion driven
displacement processes. The use of a modified single well bore, with a
downward, lateral and upward section, the uniwellT"', along with a collection
cavity connected to a producer well system, has several engineering benefits
including cost reduction, better fluid displacement and more engineering
control and economic recovery of the injection and oil recovery process.
Another specific objective is to provide a means whereby the same wellbore
perforations along the horizontal section of the wellbore can be used
sequentially for either injection or production as required by the operator.
Another specific objective is to use the movable packer between the injection
and production perforations, which forces the steam to exit the wellbore and
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enter the oil zone at a preset location upstream of the production
perforations.
Another specific objective is that after the initial oil region is depleted,
to
unseat and move the movable packer between the injection and production
perforations a preset distance along the axis of the weilbore and reseat it to
allow the steam displacement process to continue throughout the reservoir in a
new undepleted oil zone.
Another specific objective is to provide a means to considerably reduce the
distance the heated oil has to move from the steam injection point to be
produced in the welibore through the producing formations.
Another specific objective is to provide a concentric communication channel in
the formation, which allows the heated oil to move from the upper steam zone
to the perforations in the lower production zone.
Another specific objective is to provide a means whereby oil production begins
as early as possible during the injection process compared to existing
technologies like Steam Assisted Gravity Drainage (SAGD) and conventional
Thermal Enhanced Oil Recovery (TEOR).
Another specific objective is to allow the steam to replace oil and to
pressure
up the steam bank at the top, which helps to displace low viscosity, heated
oil
downwards along the interface of steam/cold reservoir oil to the producing
perforations where there exists a pressure sink because oil is being removed
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during production.
Another specific objective is to use the accumulated oil in the lateral and
upward portion of the wellbore to act as an U-tube device, which behaves
similarly to a P-trap in a household drain, allowing the steam to remain on
the
injector side of the wellbore and maximize growth of the steam zone in the
reservoir where it is more effective.
Another specific objective is to use the produced oil, which accumulates in
the
lateral and upward portion of the wellbore to act as a backpressure system
such
that the steam bank is prevented from break through by flowing down the
wellbore.
Another specific objective is to use the bottom hole pump and by controlling
surface production rates thereby allowing the reservoir pressure to be
maintained at a level such that no steam is produced because of the back
pressure in the production wellbore.
BRIEF DESCRIPTION OF THE DRAWINGS.
The present invention consists of the wellbore and associated components
shown in the figures below:
Fig. 1 Shows an overview of the uniwellT"" system with the
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downward, the horizontal lateral and the part of the upward
sections of the wellbore and the central collection cavity in
the producer well system.
Fig. 2 Shows a plan view, looking top-down, with 4 well segments
(2 uniwells) and a central producer well over the collection
cavity.
Fig. 3 Shows the use of the downhole heater in one embodiment to
heat up the near wellbore zone initially in the segment
between the injector and producer so that a communication
annulus which allows hot mobile oil to move preferentially
from the heated zone to the producing perforations.
Fig. 4 Shows an embodiment in which the reamed out annular zone
around the lateral wellbore provides a flow path from the
injector perforations to the producer perforations.
Fig. 5 Shows the cross-section (side view) of the steam cavity or
chamber which develops in the porous formation as steam is
injected into the cold medium. The oil being heavier and now
mobile by being heated flows down the "walls" of the
chamber and towards the bottom of the formation and enters
the lower production perforation zone via the communication
zone between the injector and producer perforations
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Fig.6 Shows the cross-section (side view) of the steam cavity,
central wellbore, central cavity and lateral wellbore in which
accumulated hot oil and condensed steam (water) behave as
a hydraulic plug to maintain an effective seal preventing the
steam bypass and production into the production
perforations.
Fig.7 Shows a pressure control system in the lateral wellbore using
downhole pressure regulators.
Fig. 8 Shows the combustion front used as a heat source in the
invention.
Fig. 9 Shows the well pattern distribution around a central cavity
producer well in which four injector-producer wells are
located at equally spaced 90o angles and the expected
sweep patterns for the steam displacement. This is a similar
well pattern as shown in Fig. 2. In practice, these wells can
be as many as needed to drain the areal zones effectively and
as many an nine wells can be used around a single central
producer cavity well.
Fig.10 Shows a block diagram of the operational aspects of the
invention.
Fig.11 Shows a block diagram continuing the operational aspects of
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the invention.
Fig.12 Shows a block diagram continuing the operational aspects of
the invention.
Fig.13 Shows the graph of production during a typical operation
of the prior art in which a "huff and puff' steam field
operation is implemented.
Fig.14 Shows the graph of the almost continuous steam injection
operations implemented in this invention, with the non-
injection periods for wellbore annulus heating and moving of
retractable packers.
Fig.1 5 Shows the on-off oil production graph in a more detailed
version of a part of the production cycle early in the life of
the field operations.
Fig.16 Shows the graph of the growth trend in oil production rates
as the steam injection continues followed by the natural
decline accompanying oil reserves depletion.
CA 02545505 2006-05-08
Description of Items:
No Description
1 Surface of ground
2 Central producer wellbore
3 Cavity below central welibore
4 Uniwell Wellbore
Hydrocarbon bearing formation
6 Underburden Formations
7 Overburden formations
8 Entry wellhead
9 Downward section of wellbore
Lateral section of wellbore
11 High transmissibility heated annular zone
12 Hot oil
13 Downhole Pump
14 Downhole pressure regulator device
Well Casing
16 Well Perforations for fluid injection
17 Well Perforations for oil and water production
18 Wellbore movable packer
19 Wellbore movable downhole heater
Steam bank or steam chamber
21 Oil production tanks
22 Steam
23 Well 4-spot pattern
26
CA 02545505 2006-05-08
24 Steam Generator
25 Unswept formation zone
26 Annular communication or reamed zone
27 Oil flow direction
28 Successive zones of steam growth
29 Horizontal Fluid level in cavity and wellbores
30 Combustion front
31 Flow Direction of Injected Air
32 Power Cable to Heater
33 Injected Air zone
34 Steam injection time.
35 Steam soak time
36 Oil Production rate decline curve
37a Oil Production cycle period.
37b Oil Daily production rate
37c Well Shut-in period, zero production rate
38 Wellbore heating period.
39 Oil flow rate increase trend
40 Oil flow rate decreasing trend.
27
CA 02545505 2006-05-08
DETAILED DESCRIPTION OF THE PROPOSED INVENTION
Referring now to the drawings the new invention process is described as
follows. Referring to Fig 1 and Fig 10, a central wellbore 2 is drilled from
the
surface of the ground 1 down to and passing through the hydrocarbon bearing
formation 5 as shown in step 100. The central wellbore is under-reamed by
using a reamer tool to provide a large cavity 3 up to as much as 8 feet in
radius
and several feet deep as indicated in step 101. Oilfield tools provided by
Ref. 2.
are capable of performing this operation routinely. After the central well 2
is
drilled and under-reamed it forms a production cavity 3 at its bottom. This
production cavity can hold several hundred barrels of hot oil and condensed
water. For example., a 6-foot radius cavity that is 20 feet high can hold in
excess of 1,000 barrels of fluid. This volume can be about a one-week fluid
production volume from a typical shallow stimulated steam well. As shown in
step 102 a series of uniwells 4 are drilled from the surface vertically
downwards, then laterally through the hydrocarbon pay zone at a specified
angle to intersect the production cavity 3 in the central wellbore 2. This
uniwell
4 can terminate in the cavity 3 or in another embodiment, it can continue
upwards to the surface of the ground 1 to form a separate wellhead 8.
Another embodiment described herein involves the drilling of separate multiple
uniwells 4 from the surface to intersect and terminate in the central cavity 3
as
shown in the well pattern of Fig. 2. These uniwells 4 are perforated at
predetermined locations 16, 17, along the well casing 15. In other
embodiments an "open-hole" completion can be used in which there is no steel
28
CA 02545505 2006-05-08
casing in the wellbore. This can be done in well-consolidated rock formations
but it is not a recommended approach for steam injection operations. These
perforations become production perforations 17 or injection perforations 16
depending on the timeline of the oil recovery process and their relation to
the
location of the downhole packer 18. In an "open hole" completion, this packer
18 can be a retractable inflatable packer in those situations where the well
is
completed without a casing 15. Downhole pressure regulators 14 are installed
in the distal section of the uniwell 4 before the entrance into the central
production cavity 3. In one embodiment, as shown in steps 103, 104b, a
removable downhole wellbore heater 19 is installed in the uniwell lateral
section at a point between the first injection perforations 16 and the first
set of
production perforations 17. This heater is turned on in step 104b and allowed
to heat the wellbore 4 and the near wellbore formation 5 to a high enough
temperature, in the range of 300 deg. F to 600 deg F, to significantly modify
this annular region 11 to form a high transmissibility conduit through which
hot oil from the steam displacement process will preferentially flow. The
heater
19 is removed after the heat cycle of at least 24 hours is completed. A
retractable downhole packer 18 is then installed between the injection
perforation 16 location and the production perforations 17 as shown in step
105. Another embodiment involves using a reaming bit as shown in step 104a
to form a reamed out annulus 26 enlarging the lateral wellbore 4 as shown in
Fig. 4.
As shown in step 106 and 107a, steam is generated on the surface by any of
several available thermal methods, these include among others, steam boilers,
steam generators coupled to electrical cogeneration systems which use the
29
CA 02545505 2006-05-08
power plant exhaust gas as a source of heat. The steam 22 under pressure is
injected from the surface down the uniwell wellbore 4 and on meeting the
packer 18 it is forced into the formation 5 through the injection perforation
16.
The steam forms a steam bank 20 which heats up the native oil, considerably
lowering its viscosity, displaces the oil and because of gravity segregation
as
indicated in step 108, the oil flows downwards in the steam bank or steam
chamber 20 as shown in Fig. 6. The steam bank or steam zone 20 is a heated
zone in the formation 5 in which the pore spaces of the rock are filled with
injected steam 22, condensed hot water and hot oil 12. There may also be
some hydrocarbon gas distributed in this zone. Gravity effects cause the steam
gas to inhabit the top sections and the oil and water segregate and collect at
the bottom of the zone.
As the steam zone grows, the fluid pressure increases in the steam zone and
flow is controlled by the pressure regulator 14 which keeps a back pressure on
the flow system shown by step 109 such that there is no bypass of steam from
the steam chamber 20 downwards into the production perforations 17. All of
the steam is thus forced to penetrate the formation and because of the density
differences, it accumulates in upper the region of the steam chamber 20 with
condensed water and oil 12 in the bottom. The hot oil 12 behaves as a P-trap
as shown in Fig. 6 forming a hydraulic seal keeping the oil at the bottom of
the
steam chamber column and in the annular high transmissibility conduit 11. The
height of the oil column can be modulated by fluid production to maintain a
viable hydraulic P-trap as shown later. In another embodiment, the central
wellbore segment 2 can be pressured from the surface with natural gas or some
inert gas to help implement the "P-trap" effect pneumatically in addition to
CA 02545505 2006-05-08
hydraulically.
The hot oil 12 flows downwards as indicated in step 108 under the
simultaneous effects of steam driven pressure and gravity forces to the
production zone perforations via the communication annulus 11 initially
developed in step 104a in the heated porous media or through the reamed
annulus cavity around the wellbore 4. The pressure regulator 14 maintains a
sufficient backpressure such that the hot oil 12 in the wellbore 4 behaves as
a
hydraulic seal and the steam 22 preferentially moves into the porous media
instead of axially down the wellbore 4. Oil production is allowed into the
cavity
when the regulator 14 releases the oil flow based on predetermined pressure
levels set from a zero pressure value to some finite pressure value. In
another
embodiment of the process, hot oil and hot water from the condensed steam is
allowed to accumulate in the central production cavity 3, the central wellbore
2
and the lateral wellbore 4 as shown in Fig. 6. This liquid column creates a
hydraulic seal which maintains an effective barrier at a certain vertical
level
which prevents the steam from bypassing and increases the steam injection
efficiency in the displacement process in the formation. As the cavity 3 fills
up
the downhole pump 13 initiates lifting of the displaced oil 12. When the first
production zone between the injection perforations 16 and production
perforations 17 is depleted as evidenced by steam breakthrough, the steam 22
injection is curtailed as indicated in step 111 and the wellbore packer 18 is
moved down the wellbore 4 to be reset between the next pair of injection
perforations 16 and production perforations 17. In one embodiment as shown
in step 113, the downhole packer 18 is retracted to the surface, the downhole
31
CA 02545505 2006-05-08
heater 19 is replaced at a further distance down the wellbore 4 and a new
annular region 11 is heated for the prescribed time. The heater 19 is removed,
the packer 18 is replaced and the steam 22 injection is recommenced in the
wellbore 4. In the other embodiment, wherein a reamed out annulus 26 is the
communication channel the hot oil 12 and condensed water flow down the
annulus to the production perforations 17.
Fig. 4 shows another embodiment of the invention in which a section of the
wellbore is reamed out during the drilling process to make a large annular
zone
section 26. This annular cylinder 26 around the wellbore forms the
communication zone of infinite conductivity, through which the produced fluids
move from the steam zone to the production zone. The steam 22 is injected
down the wellbore 4; the wellbore packer 18 diverts the steam into the cold
formation 5 where a steam chamber 20 develops. The formation oil is heated
by the steam and flows down the steam chamber under gravity towards the
bottom of the steam chamber. The produced oil and condensed steam flow
down the reamed out zone 26 towards the bottom of the wellbore. In this
embodiment, the produced fluids accumulate in the lateral wellbore 4 and fill
the production cavity 3.
In one embodiment, the sequence of the downhole wellbore heating, packer
placement, steam injection and oil production phases form a 4-cycle of
operations which significantly depletes a segment of the underground
reservoir. This operational cycle is repeated several times as needed to
deplete
the hydrocarbon formation 5 as shown in steps 113 to 116. The process is
complete when the formation is depleted and the last production zone is left
at
32
CA 02545505 2006-05-08
residual oil saturation. The multi-segment well system 4 with the central
producer 2 with cavity 3 form a well pattern or well template shown in Fig. 2
which is replicated across a field to completely drain and produce as much oil
as possible from the oil field. When the swept area 23 shown in Fig. 9 is
completely depleted, the injection process is terminated.
In the specific embodiment where a reamed annular zone is implemented in the
lateral section of the wellbore, since there is no heater 19 used in
implementing
the annular communication zone 26, the packer 18 is moved axially down the
lateral wellbore 4 and the injection-production processes re-initiated.
In a still further embodiment of the invention as shown in Fig. 8, a
combustion
front 30 is initiated in the underground formation 5 by injecting air into the
hydrocarbon zone as shown in step 107a. The combustion zone provides the
heat energy needed to heat the formation and lower the viscosity of the native
interstitial oil 12 which flows down the combustion front 30 and is collected
in
the central production cavity 3. The air injection perforations and oil
production
perforations are similarly moved axially down the wellbore in a manner
analogous to the steam injection process.
In engineering the steam injection operation, a computer program or simulation
analysis is routinely used in the industry to calculate the optimal required
injection time of steam into the hydrocarbon bearing formation for optimal oil
recovery. This analysis incorporates steam flow rate, steam quality, steam
pressure, formation rock properties, oil saturation and depth of formation
from
the surface.
33
CA 02545505 2006-05-08
In this invention, during the earliest steam injection time only, the
production
of hot oil is maintained at zero to allow the oil to accumulate in (a) the
bottom
of the steam bank 20 , (b) in the vertical communication zone 26 and (c) in
the
wellbore segment 4 . This accumulated hot oil 12 behaves as a hydraulic seal
preventing steam from bypassing the formation and flowing into the wellbore.
In alternative embodiments, the backpressure system described herein prevents
the production of oil into the wellbore. These no-flow embodiments are
essential and by preventing oil flow, they allow a steam bank to grow since
the
injected steam is forced to enter the formation directly heating the rock and
in-
situ hydrocarbons.
After the requisite injection time, which is nominally a matter of days, the
production of hot oil 12 and condensed water is initiated by permitting the
removal of hot fluids from the wellbore via the production system or by
lowering the backpressure on the fluid column in the wellbore. After the
production of accumulated hot oil is complete as evidenced by the incipient
flow of dry steam detectable at the surface, the fluid production is shut down
and the accumulation of hot oil and condensed water at the bottom of the
steam bank resumes. It should be noted that in this invention, except as noted
later, steam injection is a continuous operation and the oil production phase
is
started and stopped at specific operational conditions during this thermal
recovery process.
This invention differs significantly from the prior art in its implementation
in
the field. The ability of the well to be produced very soon after steam
injection
34
CA 02545505 2006-05-08
begins, allows oil revenue to begin almost immediately. Furthermore the
volumetric flow rate of oil remains relatively constant while the steam bank
is
growing and can even increase as cumulative steam injection occurs. This is
due to the larger volume of rock being contacted and heated thus lowering the
oil viscosity and also by increasing the vertical extent of the steam bank,
the
gravity effect on the oil flow column is increased, both results contribute to
increased oil flow rates.
A typical response of a steam heated heavy oil reservoir using the prior art
of
huff and puff operations is shown in Fig. 13. It should be noted that after
the
steam injection time 34, steam injection is curtailed and after the soak time
35,
the well is put on production as shown in curve element 36. There is an
initial
increase in oil production rate which immediately declines exponentially to
the
un-stimulated level after a number of days. This process is repeated several
times to fully develop the steam operations and deplete the oil reservoir.
On the other hand, the invention described herein, provides for a very
different
set of operations. Fig. shows the steam injection period 34 followed by the
period 38 in one embodiment in which the wellbore heater 19 is installed in
the wellbore and is operated for a fixed time, and during which time the
packer
18 is also moved along the wellbore. Note that the steam injection rate is
essentially constant, however in practice it is usually necessary to increase
the
injection rate over time to offset the heat losses as the steam bank increases
in
size.
Fig. 15 shows a more detailed set of operational data where the well
production
CA 02545505 2006-05-08
is intermittent. This occurs early in the steam operations since the steam
zone
or steam bank 20 is still small and growing and the accumulated oil 12 is
insufficient to be produced continuously without compromising the hydraulic
seal 29 and allowing steam breakthrough in the communication zone 26 and
the wellbore 4. This figure shows the oil production rate 37b and the oil shut-
in period 37c.
As the steam bank 20 grows, there is more reservoir formation 5 volume
available for oil production and there is a concurrent increase in the oil
production rate as shown by the trend line 39 in Fig. 16. This trend continues
to a maximum point after which there is an inevitable decline due to heat
losses, oil depletion and other factors as shown by trend line 40.
Given the increased oil flow rates which begin soon after steam injection,
coupled with the growth of the steam bank by almost continuous steam
injection, as opposed to the intermittent injection of the prior art huff and
puff
method; and the concurrent oil production increase, this invention provides
for
an improvement in the technology and prior art in a manner which allows
significant rapid development of hydrocarbon reserves from heavy and viscous
oil from subterranean formations with existing equipment and field operations
applied in a manner that has been heretofore lacking.
36
CA 02545505 2006-05-08
In this patent certain United States patents, patent applications, and other
materials (e.g., articles) have been incorporated by reference. The text of
such
U.S. patents, U.S. patent applications, and other materials is, however, only
incorporated by reference to the extent that no conflict exists between such
text and the other statements and drawings set forth herein. In the event of
such conflict, then any such conflicting text in such incorporated by
reference
U.S. patents, U.S. patent applications, and other materials is specifically
not
incorporated by reference in this patent
Further modifications and alternative embodiments of various aspects of the
invention may be apparent to those skilled in the art in view of this
description.
Accordingly, this description is to be construed as illustrative only and is
for the
purpose of teaching those skilled in the art the general manner of carrying
out
the invention. It is to be understood that the forms of the invention shown
and
described herein are to be taken as the presently preferred embodiments.
Elements and materials may be substituted for those illustrated and described
herein, parts and processes may be reversed, and certain features of the
invention may be utilized independently, all as would be apparent to one
skilled
in the art after having the benefit of this description of the invention.
Changes
may be made in the elements described herein without departing from the
spirit and scope of the invention as described in the following claims.
37
CA 02545505 2006-05-08
References:
1. SPE, The Society of Petroleum Engineers 222 Palisades Creek Dr.,
Richardson, TX, 75080, U.S.A., www.spe.ora.
2. Harvest Oil Tool Company LLC, 6801 North Peterson Road, Sedalia, CO
80135, U.S.A. www.harvesttool.com
3. Dynatec Corporation. www.dynatec.ca.
4. "A Comparison of Mass Rate and Steam Quality Reductions to Optimize
Steamflood Performance", Topical Report 108, Gregory L. Messner, July
1998, Stanford University, Stanford, California
38
