Note: Descriptions are shown in the official language in which they were submitted.
CA 02549784 2006-05-09
DESCRIPTION:
CROSS REFERENCE TO RELATED APPLICATIONS
This application claims priority from United States Disclosure Document
589,546 by Dr. Henry Crichlow filed on 11 /07/2005 and United States
Provisional Patent 60/772,515 filed on 2/13/2006 by Dr. Henry Crichlow and
US utility patent application 11 /279,948.
INTRODUCTION:
This invention relates generally to a new technology application and a new
type
of oil well system for recovery of hydrocarbons from subterranean heavy oil
bearing formations including tar sands and oil shales.
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 a combination of vertical and horizontal wells are drilled from the
surface down to an oil bearing formation. In addition, this invention utilizes
a
collection cavity drilled below the vertical wellbore by under-reaming to form
a
collection site for the produced oil. In addition, a vertical communication
zone
is first developed in the annular region between the top injection
perforations
and the lower producing formation by a removable high temperature wellbore
heater or by the under-reaming of a portion of the vertical wellbore. A packer
separates the injection zone from the production zone such that displaced oil
flow occurs in the annular communication zone region from top to bottom.
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The technology is a new application using some elements of an existing
drilling, completion and production technology, which have hitherto been used
in conventional oil well drilling. A novel completion technique uses injection
and production perforations separated by a wellbore packer and the use of a
vertical communication zone.
FIELD OF INVENTION:
THIS INVENTION is a new approach for oil recovery in heavy oil systems using
injected hot fluid, in one embodiment, steam, a vertical annular hot
communication zone and a downhole collection cavity under-reamed in the
vertical wellbore. The invention is particularly suited to making heavy oil
formations, oil shales and tar sands producible by a single we!lbore drilled
into
and through the hydrocarbon pay zone. 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.
With this invention, the operator drills a new type of well, completes it, as
indicated herein and produces the oil during the oil displacement process.
BACKGROUND OF THE INVENTION
Introduction:
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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 viscosity, 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 and allows the oil to flow
from the
formation into the producing wellbore. Today, the steam injection can be done
in a continuous fashion in which steam displaces oil from hot zones to the
producer wells or intermittently as in the so-called "huff and puff' or cyclic
steam process in which the steam is injected into, and oil produced from the
same well after a predetermined soaking period. Oil recovery by steam
injection involves a combination of physical processes including, gravity
drainage, steam drive and steam drag to move the heated oil from the upper oil
zone into the lower producing zone.
The most significant oil recovery problem with heavy oil, tar sands and
similar
hydrocarbonaceous material is the extremely high viscosity of the native
hydrocarbons. At reservoir conditions, the oil viscosity ranges from 10,000 cp
at the low end of the range to 5,000,000 cp at the high end. 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
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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.
Because of the extremely high viscosity of the heavy hydrocarbon in-situ, it
is
difficult if not impossible to physically move the displaced oil from the hot
mobile location, through the cold porous rock formation to the producing
wellbores. By implementing the novel processes which are taught in this
application by this invention, especially the development of a hot annular
vertical communicative zone of reduced viscosity and increased
transmissibility, the oilfield operator can see improved performance, lower
costs, better oilfield management, and allow for efficient and orderly
development of petroleum resources.
In one embodiment of the invention, 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.
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THIS NEW INVENTION provides an improvement in the oil recovery method
whereby the operator drills a typical vertical well which is drilled from the
surface down to the producing formation and continues past the pay zone into
the under-burden. A cavity is developed below the pay zone by under-reaming
the vertical wellbore to form a collection cavity. This under-reaming can be
made up to 8 or 9 feet in diameter using standard reaming technology and
tools used in the oil and gas industry today. The volumetric size of the
cavity
will be sized according to the required and expected oil production from each
well.
This cavity is an additional implementation into which the hot displaced oil
is
allowed to drain from the heated zones into this collection cavity. Standard
pumping equipment lifts the produced oil from the collection cavity. The
techniques proposed herein uses 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.
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
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a combustion front in the reservoir to displace the insitu oil from the
injection
wellbore to the production wellbore.
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 formation with extremely
highly
viscous oil, 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 in the opposite direction against the invading high
pressure steam through the same perforations through the rock pore structure.
This situation is not only physically impossible but it thermodynamically
impossible for the 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 weilbore 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 petroieum
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near the well. This causes 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 or
simultaneously from the surface weffheads.
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 in
a
vertical direction 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 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 well bore. The
vertical wellbore is used to actually produce the reservoir fluids. The
horizontal
wellbore provides the conduits, which direct the fluids to the vertical
producing
wellbore.
US Patent 5,626,193 by Nzekwu et al disclose a single horizontal well with
multiple tubing elements inside the major welibore. 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 backwards 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
in the collection zone by a set of valves or a pumping system which is
designed
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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 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 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.
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
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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 from 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
with the other well or wells.
US 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 byvarious
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
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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.
The Society of Petroleum Engineers Ref. 1, SPE paper 20017 teaches a computer
simulation of a displacement process using a concentric wellbore system of
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 welibore from
just above the bottom packer to the injection perforations near the top of the
tar sand. This 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 perforations near the top
of the tar sand and the fluid production perforations near the bottom of the
tar
sand. This process requires 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
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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.
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.
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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 2 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
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 this 3,994,341 embodiment,
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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 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 saturated 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
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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 a combination of effects. These
include;
(1) the inability of the process to inject the hot fluid into cold highly
viscous
oil saturated formations having a limited conductivity where the hydrocarbon
viscosities are in excess of 106 cp. With this viscosity the liquid is
essentially
immobile at reservoir temperature.
(2) the inability to overcome the viscosity difference effect, wherein 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 oil having a high viscosity of 100,000 cp. This flow ratio is based
directly
on the viscosity ratios of 100,000/.02;
(3) the inability of the prior methods to prevent bypass of injected fluid
directly from the injector source towards the producing sink;
(4) the inability of the prior methods to form and maintain a viable
communication zone from the steam zone or chamber to the producing sink
while simultaneously preventing bypass and early breakthrough of steam;
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(5) the inability of the prior processes to effectively utilize the gravity
drainage effects created by the low density of the hot steam compared to the
high density of condensed water and hot oil;
(6) the inability of the prior processes 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 measurable production response of the displaced
oil in the production wells;
(8) The inability of the existing technology to maintain and sustain oil
production rates when applied to large patterns of several wells;
(9) Finally the use of overly complex equipment of questionable operational
effectiveness to implement the process in the field.
SUMMARY OF THE INVENTION:
THIS NEW INVENTION provides an improvement in heavy oil recovery whereby
the operator drills a specially designed vertical well. A segment of this well
is
enlarged to form a production cavity, a plurality of lateral wells is drilled
into
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the producing formation from the vertical wellbore by cutting a window in the
vertical wellbore casing and drilling out laterally. An additional
implementation
is the development of a collection cavity in the vertical wellbore, into which
the
hot displaced oil is allowed to drain from the lateral horizontal wells in to
this
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.
In this oil recovery method the operator drills a vertical well which is
drilled
from the surface down to the producing formation and continues past the pay
zone into the under-burden. A cavity is developed below the pay zone by
under-reaming the vertical wellbore to form a collection cavity. This under-
reaming can be made up to 8 or 9 feet in diameter using standard reaming
technology and tools used in the oil and gas industry today as shown in Ref.
3.
The volumetric size of the cavity will be sized according to the required and
expected oil production from each well.
The hot displaced oil is allowed to drain from the heated zones into this
collection cavity. Standard pumping equipment lifts the produced oil from the
collection cavity.
An object of this invention is to provide an improved process for recovery of
heavy oils and similar hydrocarbons from subterranean formations. The use of
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a single well bore, with an isolation packer vertically separating injection
and
production perforations, along with a collection cavity connected to a
producer
well system. In one embodiment, the communication between the injection
zone and production zone is made possible by the initial heating via downhole
internal wellbore heater of the near wellbore annulus, to a high enough
temperature such that the in-situ heavy oil is lowered in viscosity. The
heated
zone then becomes an annular communication zone for the fluids from the
injection zone to move under gravity and hydraulic pressure to the lower
production perforations. Bypassing of injected steam is prevented by the U-
Tube effect of the produced fluid in the cavity and production tubing along
with
an optional downhole pressure regulator if required.
An object of this invention is to provide an improved process for recovery of
heavy oils and other highly viscous hydrocarbons from subterranean formations
by exploiting the advantages provided by gravity drainage effect in the
displacement process of heated viscous oils in porous formations using the
steam driven displacement mechanisms. The use of a modified single well bore
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 accelerated economic recovery of the injection
and oil recovery process.
Another specific objective is to provide a means whereby the same wellbore
perforations along the vertical section of the wellbore can be used
sequentially
for either injection or production as required by the operator.
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Another specific objective is to use the movable packer between the injection
and production perforations, which forces the steam to exit the wellbore and
enter the oil zone at a preset location upstream of the production
perforations.
Another specific objective is 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 wellbore and reseat it to
allow the steam displacement process to continue throughout the reservoir in a
new undepleted or virgin oil zone.
Another specific objective is to provide a concentric annular communication
channel in the formation, which allows the heated oil to move from the upper
steam zone to the production perforations in the lower production zone.
Another specific objective is to provide a means to considerably reduce the
distance the heated oil has to move through the producing formations from the
steam injection point to be produced in the wellbore.
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), where oil production takes place after a
considerable length of steam injection ranging from several weeks to several
months.
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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 localized pressure sink because oil is being
removed during production.
Another specific objective is to use the accumulated oil in the wellbore to
act as
a hydraulic seal, allowing the steam to remain uppermost in the injector zone
of
the wellbore and thereby 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
production zone of the wellbore to act as a backpressure system such that the
steam bank is prevented from vertical breakthrough by flowing down the
wellbore.
Another specific objective is to control 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 keeping the
steam isolated in the steam bank.
BRIEF DESCRIPTION OF THE DRAWINGS.
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The present invention consists of the wellbore and associated components
shown in the figures below:
Fig.1 Shows a cross-section of the vertical wellbore, the pay zone,
perforation zones, the steam chamber, the isolation packer,
the wellbore cavity and the downhole equipment.
Fig.2 Shows a cross-section with a horizontal wellbore
embodiment, the removable packer, the vertical
communication zone, the collection cavity and the
production perforations.
Fig. 3 Shows the implementation of the removable downhole high
temperature heater, which heats, up an annular region
between the upper and lower perforations which provide a
vertical communication zone for the hot displaced fluids.
Fig. 4 Shows the flow regimes in which the steam builds an
upper chamber because of lower fluid density. The hot
mobile displaced oil moves down by gravitational counter-
flow along the steam/oil interface and down to the
communication zone and finally into the production cavity at
the bottom of the vertical wellbore. The oil collects in the
lower cavity from which it is pumped to the surface.
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Fig. 5 Shows the three zones of activity involved in the process.
The upper injection zone, the central communication and the
bottom production zone. There is a major pressure gradient
from the high-pressure upper zone down to the lower
pressure production zone. The fluid flow follows the
pressure gradient in the annular communication zone in the
rock formation.
Fig. 6 Shows an end view of Figure 2 which shows a horizontal
wellbore in axial view, drilled into the pay zone. The
displacement process and collection of oil in the lower cavity
is shown.
Fig. 7 Shows the "P-trap" effect in which the accumulated oil in
the production cavity and communication zone behaves like
a hydraulic seal limiting steam bypass.
Fig. 8 Shows an embodiment in which a reamed concentric
annular region is used as the communication zone.
Fig. 9 Shows the embodiment with a reamed concentric annular
communication zone in which the control of fluid level by oil
production at the surface, allows a "P-trap" hydraulic seal to
prevent steam bypass from the steam chamber.
CA 02549784 2006-05-09
Fig.10 Shows a block diagram of the operational aspects of the
invention.
Fig.11 Shows a block diagram continuing the operational aspects of
the invention.
Fig.1 2 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.15 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.
26
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List of elements
No Description
1 Surface of ground
2 Central producer wellbore
3 Cavity below central wellbore
4 Lateral Wellbore for Injecting Steam
Hydrocarbon bearing formation
6 Underburden Formations
7 Overburden formations
8 Entry wellhead
9 Downward section of wellbore
Injection Displacement Zone
11 High transmissibility heated annular zone
12 Hot oil
13 Downhole Pump
14 Window cut in the Casing for lateral wellbore drilling
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 Fluid Communication Zone
22 Steam
23 Liquid Seal by hot fluid
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CA 02549784 2006-05-09
24 Accumulation Zone
25 Unswept formation zone
26 Annular reamed zone
27 Oil flow direction
28 Successive zones of steam growth
29 Horizontal Fluid seal level in communication zones and
wellbores
30 Wellbore liner
31 Production tubing
32 Power Cable to Heater
33 Axis (end) view of horizontal (lateral) wellbore
34 Backpressure device
35 Steam injection time.
36 Steam soak time
37 Oil Production rate decline curve
38a Oil Production cycle embedded in the steam injection cycle.
38b Oil Daily production rate
38c Well Shut-in period, zero production rate
39 Wellbore heating period.
40 Oil flow rate increase trend
41 Oil flow rate decreasing trend.
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CA 02549784 2006-05-09
DETAILED DESCRIPTION OF THE PROPOSED INVENTION
Referring now to the drawings the new method 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
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 diameter
and
several feet deep as indicated in step 101. This cavity 3 can be implemented
in
the oil formation 5 or ideally in the under-burden formation 6 or in a both
zones at the same time. Standard oilfield tools as provided by Ref. 2 are
capable of performing this operation routinely. After the central well 2 is
drilled and under-reamed to form a production cavity 3 as shown in step 101,
the central wellbore 2 is completed and cemented in the formation 5 with steel
casing 15 and perforations 16 and 17 made at pre-selected intervals is the
wellbore as indicated in step 102. In other embodiments an "open-hole"
completion can be used in which there is no steel casing 15 in the wellbore.
This can be done in well consolidated rock formations.
In another embodiment a plurality of horizontal laterals 4 shown in step 103,
are drilled out from the vertical wellbore 2 by cutting windows 14 and
drilling
out separate lateral segments as shown in Fig. 2. These lateral wellbores 4
are
used for injection of steam 22 into the oil-bearing formation 5 forming a
steam
bank 20. 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
29
CA 02549784 2006-05-09
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
steam
zone 20.
As shown in step 104 of Fig. 10, a process is selected to implement the fluid
communication zone 21. In one embodiment as shown in step 105a, a
downhole heater 19 with an electrical power cord 32 is installed as shown in
Fig. 3. The heater 19 is initiated and left in place for a predetermined time
to
heat up the casing 15 and adjacent formation 5 to a temperature high enough
to lower the oil viscosity, modify the rock permeability and change the fluid
saturations. A temperature between 200 deg. C and 700 deg. C is maintained in
the formation 5 to achieve these changes. The rock is modified thermally and a
concentric radial zone 21 is developed in the formation surrounding the
central
wellbore 2. Other types of heaters like gas-fired devices can be used without
changing the hydrocarbon recovery process.
Further referring to Fig. 1, a production system is implemented by installing
a
production string 31 commonly called tubing string, a downhole pump 13 and
surface facilities to collect and transfer the produced oil. The production
system
is operated either continuously or intermittently.
Referring to Fig. 10, as shown in step 106, and referring to Fig. 1, a movable
and retractable downhole packer 18 is installed on the production string 31 in
the annulus between the production string 31 and the casing 15 at a point
below the injection steam bank zone 20 and above the first set of production
perforations 17. In an "open hole" completion, this packer 18 can be a
CA 02549784 2006-05-09
retractable inflatable packer in those situations where the well is completed
without a casing 15.
The following steps illustrate the implementation of the process:
Step 1 Drill a vertical wellbore 9 down to and through the hydrocarbon pay
zone 5 as shown in Fig. 1.
Step 2 As shown in Fig. 1, under-ream a cavity 3 below the productive pay
zone 5 sufficient to contain the required amount of displaced oil 12.
Step 3 In an alternative embodiment, as shown in Fig. 2, a plurality of
horizontal wellbores 4 are drilled at varying heights into the pay zone 5 from
the vertical wellbore 9. These horizontal wells are drilled throughout the pay
zone for future utilization as injection points for steam as the cycle of
operations is repeated as shown in Step 16 below.
Step 4 Complete the well by making the required injection perforations 16
in the upper section of the wellbore 9 and the production perforations 17 in
the
lower portion of the pay zone 5 as shown in Fig. 1.
Step 5 In one embodiment install a high temperature downhole heater 19
in the casing at a selected location of the wellbore 2 as shown in Fig. 3.
Step 6 Heat the wellbore 2 and surrounding rock formation 5 for a
sufficient time and at a calculated temperature sufficient to create a
cylindrical
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CA 02549784 2006-05-09
annular hot zone of increased fluid conductivity, which creates a vertical
communication 21 between the upper and lower perforation zones in the rock
formation.
Step 7 The heater 19 is removed from the wellbore 2.
Step 7a In one embodiment, shown in Fig. 8, an annular concentric cavity 26 is
reamed out around the central wellbore 2 to form a communications zone from
the top of the formation to the bottom. In this embodiment, the heater is not
used to modify the near wellbore zone.
Step 8 As shown in Fig. 1 a movable isolation packer 18 is installed in the
wellbore 2 between the upper perforations 16 and the lower perforations 17.
The isolation packer 18 forces the injected steam 22 to be injected into the
pay
zone 5. The production tubing 31 is installed through the packer 18 in a
conventional manner as used in the oil industry.
Step 9 As shown in Fig. 1, steam 22 is injected into the upper perforations
16. Steam injection can be either continuous or intermittent.
Step 9a In another embodiment, shown in Fig. 2, steam 22 is injected into the
horizontal wells 4 which are drilled into the oil formation S. Steam injection
can
be either continuous or intermittent.
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Step 10 As shown in Fig. 1, steam 22 forms a viable steam chamber 20 in the
upper regions of the pay zone 5. The steam is prevented from bypassing
downwards into the production zone by the U-tube effect of fluid in the
wellbore creating a substantial backpressure and additionally a downhole
backpressure valve 34 in the tubing 31 can be used to create this backpressure
if needed.
As shown in Fig. 7 The oil accumulation 12 in the production system can be
used as a modulation mechanism by "choking" the surface oil production rate
such that a hydraulic seal 23 develops because of the fluid level 29 between
light gaseous steam and heavier hot oil. This seal prevents steam bypassing
the
steam bank 20 and going directly downwards into the collection cavity 3 via
the
communication zone 21.
Step 11 As shown in Figs. 6,7,8,9, the heated and mobile low viscosity oil 12
and the condensed steam now as hot water, flow down the interface of the
steam chamber 20 along the flow lines 27 and through the communication
zone 21 which acts as a high conductivity channel, compared to the almost
zero conductivity of the high viscosity portion of the cold pay zone 5. The
oil
12 and water accumulate in the collection cavity 3 below the pay zone 5.
Step 12 The conventional downhole production pump 13 lifts the produced oil
to the surface through the production tubing 31, which is installed through
the
isolation packer 18, illustrated in Fig.1.
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Step 13 As shown in Figs. 5,6,7,8,9 as steam injection continues the steam
chamber 20 grows and the displaced oil volume 10 increases.
Step 14 The maximum size of the steam chamber is dictated by the rate of
steam injection and the total steam volume injected.
Step 15 The oil zone is depleted when the steam injection completely fills the
pay zone and steam 22 production occurs from the production perforations 16.
This determined by a sudden rise in temperature and steam gas production
through the production perforations
Step 16 The steam injection process is re-started. Essentially steps 5 to15
are
repeated. To start, steam injection is curtailed at the surface. The tubing
string
31 is pulled from the wellbore, The removable packer 18 is removed, in one
embodiment the downhole heater 19 is re-inserted between the next vertically
lower pair of perforations and the formation heated to form a new vertical
communication zone 21 as shown in step 5 above. In the other embodiment,
whereby an annular communication zone 26 was reamed out earlier there is no
need for a heater device 19 to set up this communication zone 21. The existing
zone is already in place and functioning. The movable packer 18 is moved
down the wellbore between the next pair of injection 16 and production
perforations 17.
In engineering the steam injection operation, a computer program or simulation
analysis is routinely used in the petroleum industry to calculate the optimal
required injection time of steam into the hydrocarbon bearing formation for
34
CA 02549784 2006-05-09
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.
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 21 in one embodiment and 26 in
another embodiment, and
(c) in the wellbore segment 2.
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
elements of the invention 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 12 is complete as evidenced by the incipient
flow of gaseous 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
CA 02549784 2006-05-09
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
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 thermal operations is shown in Fig. 13. In the huff and puff
operations the same wellbore is used for steam injection and after a "soak"
period, oil production from the same open perforations in the oil formation
zone. The subject invention taught herein, differs significantly from this
huff
and puff method. It should be noted that after the steam injection time 35,
steam injection is curtailed and after the soak time 36, the well is put on
production as shown in curve element 37. 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.
36
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On the other hand, the invention described herein, provides for a very
different
set of operations. Fig. 14 shows the combined steam injection and oil
production period 35 followed by the period 39 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
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 zones 21 and
26 and the wellbore 2. This figure shows the oil production rate 38a and the
oil
shut-in period 38c.
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 40 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 41.
When the oil zone is completely depleted after several operational cycles of
moving the injection system downwards between the injection-production pairs
37
CA 02549784 2006-05-09
of perforations, the steam injection is stopped. This technology provides for
a
Single Well Accelerated Production (SWAPTM) method of hydrocarbon recovery
which is capable of producing oil at rapid rates compare to the current SAGD
and TEOR methods of the existing art.
To develop an oil field several wells are drilled and the operations carried
out at
each well singly or in groups or patterns in a manner described herein.
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.
In this patent certain U.S. 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
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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 claims.
References:
1. The Society of Petroleum Engineers 222 Palisades Creek Dr., Richardson, TX
75080, U.S.A., www.spe.org.
2. "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.
3. Harvest Oil Tool Company LLC, 6801 North Peterson Road, Sedalia, CO
39
CA 02549784 2006-05-09
80135, U.S.A. www.harvesttool.com
