Single horizontal wellbore process/apparatus for the in-situ extraction of viscous oil by gravity action using steam plus solvent vapor

A conduction heating, gravity assisted, single well, process for removing viscous hydrocarbonaceous fluids from a reservoir penetrated by a horizontal wellbore. Steam and a gas soluble in hydrocarbonaceous fluids are circulated into the wellbore at or below the reservoir pressure through an upper perforated conduit of the horizontal wellbore. Circulation is continued so as to allow steam to heat the reservoir by conductance while gas enters the hydrocarbonaceous fluids. Thus, heated hydrocarbonaceous fluids having a reduced viscosity flow from the reservoir around the horizontal wellbore where the fluids are produced to the surface by a lower conduit within the horizontal wellbore. The lower conduit is open along its length so as to be in fluid communication with the reservoir for the length of the horizontal wellbore.

FIELD OF THE INVENTION 
This invention relates to a process for the recovery of highly viscous 
hydrocarbons from subterranean oil reservoirs. Specifically, the invention 
relates to continuously injecting steam and solvent while continuously 
producing oil and condensed steam from a single horizontal wellbore. 
BACKGROUND OF THE INVENTION 
World energy supplies are substantially impacted by the world's heavy oil 
resources. Indeed, heavy oil comprises 2,100 billion barrels of the 
world's total oil reserves. Processes for the economic recovery of these 
viscous reserves are clearly important. 
Asphalt, tar, and heavy oil are typically deposited near the surface with 
overburden depths that span a few feet to a few thousands of feet. In 
Canada, vast deposits of heavy oil are found in the Athabasca, Cold Lake, 
Celtic, Lloydminster and McMurray reservoirs. In California, heavy oil is 
found in the South Belridge, Midway Sunset, Kern River and other 
reservoirs. 
In large Athabasca and Cold Lake bitumen deposits oil is essentially 
immobile--unable to flow under normal natural drive primary recovery 
mechanisms. Furthermore, oil saturations in these formations are typically 
large. This limits the injectivity of a fluid (heated or cold) into the 
formation. Moreover, many of these deposits are too deep below the surface 
to be mined effectively and economically. 
In-situ techniques of recovering viscous oil and bitumen have been the 
subject of much previous investigation. These techniques can be split into 
three categories: 1) cyclic processes involving injecting and producing a 
viscosity reducing agent; 2) continuous steaming processes which involve 
injecting a heated fluid at one well and displacing oil to another set of 
wells; and 3) the relatively new Steam (or Solvent) Assisted Gravity 
Drainage process. 
Each of these techniques has large limitations if application to the very 
viscous Athabasca or Cold Lake reservoirs is desired. 
Cyclic steam or solvent stimulation in these two reservoirs are severely 
hampered by the lack of any significant steam injectivity into the 
respective formations. Hence, in the case of vertical wells a formation 
fracture is required to obtain any significant injectivity into the 
formation. Some success with a fracturing technique has been obtained in 
the Cold Lake reservoir at locations not having any significant underlying 
water aquifer. However, if a water aquifer exists beneath the vertical 
well located in the oil bearing formation, fracturing during steam 
injection results in early and large water influx during the production 
phase. This substantially lowers the economic performance of wells. In 
addition, cyclic steaming techniques are not continuous in nature thereby 
reducing the economic viability of the process. Clearly, steam stimulation 
techniques in Cold Lake and Athabasca are severely limited. 
Vertical well continuous steaming processes are not technically or 
economically feasible in the very viscous bitumen reservoirs. Oil mobility 
is simply far too small to be produced from a cold production well as is 
done in California type of reservoirs. Steam injection from one well and 
production from a remote production well is not possible unless a 
formation fracture is again formed. Formation fractures between wells are 
very difficult to control and there are operational problems associated 
with fracturing in such a controlled manner as to intersect an entire 
pattern of wells. Hence, classical steam flooding, even in the presence of 
initial fluid injectivity artificially induced by a fracture has 
significant limitations. 
Steam Assisted Gravity Drainage (SAGD) is disclosed in U.S. Pat. No. 
4,344,485 which issued to Butler in 1982. SAGD uses a pair of horizontal 
wells connected by a vertical fracture. The process has several advantages 
to steam stimulation or continuous steam injection. One advantage is that 
initial steam injectivity is not needed as steam rises by gravity above 
the upper well thereby replacing oil produced at the lower well. Another 
advantage is that since the process is gravity dominated and steam 
replaces voided oil, good sweep efficiency is obtained. Yet another 
advantage is since horizontal wells are utilized, good oil rates may be 
obtained by simply extending the length of the well to contact more of the 
oil bearing formation. In the SAGD process, steam is injected in the upper 
horizontal well while oil and water are produced at the lower horizontal 
well. Steam production from the lower well is controlled so that the 
entire process remains in the gravity dominated regime. A steam chamber 
rises above the upper well and oil warmed by conduction drains along the 
outside of the chamber to the lower production well. The process has the 
advantages of high oil rates and good overall recovery. It can be used in 
the absence of a vertical fracture. 
However, one serious limitation of this process in practical application is 
the need to have two parallel horizontal wells--one beneath the other. 
Those skilled in the art of drilling horizontal wells will immediately 
recognize the difficulty in drilling two parallel horizontal wells, one 
above the other, with any real accuracy for any real horizontal distance 
from the surface. 
Thus, what is needed is a process that provides the advantages of the Steam 
Assisted Gravity Drainage process but removes the difficulty of drilling 
two precisely spaced, parallel horizontal wellbores from the surface. 
SUMMARY OF THE INVENTION 
In accordance with the above stated need, an improved thermal recovery 
process for continuous steam and solvent injection along with concomitant 
oil production using a single horizontal wellbore is described. Steam 
passes out of slots along an upper portion of a horizontal wellbore 
containing two conduits or compartments. Steam percolates up through the 
formation. Oil flows downwardly both countercurrently and tangentially to 
the rising steam. Oil collects around the horizontal well where steam is 
continuously circulated. Steam circulates down the wellbore's outer 
compartment and back through its inner compartment. The inner compartment 
is open along a lower portion of the horizontal wellbore. Downwardly 
flowing oil from the reservoir collects in a pool around the wellbore and 
is pulled into the inner compartment along the length of the wellbore. Oil 
flow into the inner compartment is facilitated by conduction heating due 
to steam circulation throughout the apparatus. 
Steam and a vaporous oil soluble solvent, such as CO.sub.2, or C.sub.1 
-C.sub.4 hydrocarbons, are circulated through an outer compartment of a 
dual compartment single production/injection tubing string. Pressure of 
this outer compartment is controlled such that steam and oil soluble vapor 
flow, under the influence of gravity, into the hydrocarbonaceous fluid 
containing reservoir through slots along the top of the compartment. Steam 
and oil soluble vapor not taken by the formation are circulated back 
through the slotted second inner production compartment. 
In the preferred embodiment of this process, warmed oil drains down through 
the viscous hydrocarbonaceous formation due to the action of gravity. It 
then collects in a pool around the wellbore. Vapor (steam and solvent) 
rises up through the liquid pool by gravity. Steam circulation within the 
wellbore provides heat to the oil pool surrounding the wellbore thereby 
further reducing its viscosity and facilitating its movement into the 
inner production compartment. 
Steam and oil soluble vapor enter the formation: (1) at a rate dictated by 
the rate of oil drainage to the oil pool; (2) the rate at which oil and 
condensed water are withdrawn; and (3) the pressure of the outer 
compartment. A control scheme is utilized which limits the production of 
steam in the produced fluids such that the process is forcibly placed in a 
gravity dominated region. Therefore, the produced fluids do not contain 
large quantities of steam. Control is accomplished by raising the inner 
compartment's pressure when steam is sensed at the surface. Hence, steam 
is not permitted to flow directly from the outer, upper compartment or 
conduit of the horizontal wellbore to its lower, inner compartment or 
conduit. Steam only flows into the formation by purely gravitational 
forces away from the upper slots. Steam will alternately break through at 
the lower, inner compartment or conduit. However, by operating steam 
control effectively, the process will be controlled in the gravity 
dominated region. 
A temperature gradient will be set up inside of the zone where steam is 
predominant as a result of solvent vapor diffusion within the steam zone. 
Solvent vapor tends to flow upwardly with the steam. When steam condenses 
the solvent vapor remains in the vapor phase. In general, a larger mole 
fraction of the solvent vapor will be collected at the surfaces of 
condensation near the steam/oil boundary. A diffusion of the solvent vapor 
in the direction opposite steam flow will occur resulting in a partial 
pressure gradient within the steam zone. Thus, the temperature of the 
steam zone will be largest near the wellbore and smallest at the outer 
boundary of the steam zone. This temperature gradient within the steam 
zone will facilitate stripping of the oil as it drains down through the 
steam zone. Lighter hydrocarbons will be stripped in the successively 
warmer zones within the steam zone. 
It is therefore a primary object of this invention to provide an 
economically viable method for recovering initially immobile 
hydrocarbonaceous materials in reservoirs where fracturing is not an 
option due to an underlying water aquifer and dual, parallel horizontal 
wells are not practical. 
It is another object of this invention to extract viscous hydrocarbonaceous 
materials with a gravity process using a single horizontal well. 
It is yet another object of this invention to remove viscous 
hydrocarbonaceous materials from a subterranean oil reservoir by heated 
oil flow through and around steam rising by gravity through the formation 
above a single horizontal well. 
It is still another object of this invention to utilize the countercurrent 
nature of flow within the reservoir to extract lighter ends of heavy crude 
thereby providing for an in-situ separation process. 
It is still yet another object of this invention to provide for a 
continuous thermal oil production process from a single horizontal 
wellbore. 
It is a further object of this invention to provide for an oil production 
process which substantially reduces sand production during oil inflow.

DESCRIPTION OF THE PREFERRED EMBODIMENTS 
This invention is directed to a method for removing immobile viscous 
hydrocarbonaceous fluids from a formation or reservoir which formation is 
penetrated by a horizontal wellbore. The horizontal wellbore contains a 
lower or inner conduit 1 and an outer or upper conduit 2. Placed within 
the outer conduit 2 along its horizontal length are perforations 3. Lower 
conduit 1 is open along its bottom or lower side through an opening 9. The 
relationship between the lower conduit 1 and outer or upper conduit 2 is 
shown in a cross-sectional view of FIG. 1. 
In the practice of the invention, referring to FIG. 2, steam and a gas 
soluble in hydrocarbonaceous fluids are circulated down outer or upper 
conduit 2. Steam and the gas are continually circulated into outer 
compartment 2 at a pressure at or below the reservoir pressure but also 
below the reservoir's fracture pressure. In this manner pressurized steam 
entry into the reservoir is substantially avoided. Steam flows into the 
formation by purely gravitional forces away from upper perforations 3. 
Additionally, steam when circulated in this manner heats the area 
surrounding the wellbore by conduction heating. Gas circulated into upper 
or outer compartment 2 enters the formation by diffusion so as to enhance 
the reduction in viscosity of the hydrocarbonaceous fluids. 
Steam is allowed to continually circulate in and out of the horizontal 
wellbore for a time sufficient to heat the reservoir by transient 
conduction. The reservoir is heated to a temperature sufficient to cause 
the hydrocarbonaceous fluids to become reduced in viscosity and thereby 
move to a lower section of the wellbore where said fluids exit the 
reservoir via opening 9 along the lower or inner compartment 1 of said 
wellbore. These hydrocarbonaceous fluids of reduced viscosity are 
continually removed from the reservoir via opening 9 in lower or inner 
conduit 1. A wellbore configuration which can be used in the practice of 
this invention is disclosed in U.S. Pat. No. 4,067,391 which issued to 
Dewell on Jan. 10, 1978. This patent is hereby incorporated by reference 
herein. 
Steam and soluble gas circulation into outer or upper conduit 2 is 
controlled by control valve 10. Gases soluble in hydrocarbonaceous fluids 
which can be used herein include carbon dioxide, nitrogen, flu gas, and 
C.sub.1 -C.sub.4 hydrocarbons. Once hydrocarbonaceous fluids of reduced 
viscosity begin to move from the reservoir, pressure within the outer or 
upper conduit 2 is controlled so that steam and gas soluble in 
hydrocarbonaceous fluids flow, under the influence of gravity, into the 
reservoir through wellbore perforations 3. Steam and gases that are not 
taken into the formation are circulated back through inner or lower 
compartment 1 where they exit the horizontal wellbore to the surface. 
While the warmed hydrocarbonaceous fluids of reduced viscosity drain 
downwardly through viscous hydrocarbonaceous fluids contained in the 
reservoir by gravity action, a hydrocarbonaceous fluid pool forms around 
the horizontal wellbore. 
As is shown in FIGS. 1 and 2, steam and gas which have not been taken up by 
the hydrocarbonaceous fluids in the reservoir tend to flow downwardly into 
pool 4 which surrounds the wellbore whereupon they enter opening 9 in 
lower or inner conduit 1. Steam circulation within the wellbore provides 
heat to pool 4 surrounding said wellbore which facilitates the oil's 
movement into lower or inner conduit 1 where it is produced to the 
surface. 
Steam and gases are taken by the formation or reservoir at a rate which is 
dictated by the rate of oil drainage int pool 4. The rate at which 
hydrocarbonaceous fluids and condensed steam are withdrawn is controlled 
by the pressure in outer or upper conduit 2. The process is controlled so 
as to limit the production of steam in fluids produced to the surface so 
that the process is forcibly placed in a gravity dominated area. In this 
manner produced fluids do not contain large quantities of steam. This 
control is maintained by raising the pressure within the inner or lower 
compartment 1 when steam is sensed at the surface. Therefore, steam is not 
permitted to flow directly from outer or upper conduit 2 into lower or 
inner conduit 1. Steam can only flow into the reservoir or formation away 
from upper perforations 3 which is accomplished by pure gravity while the 
process is being utilized. Steam will alternatively break through at lower 
or inner conduit 1. By operating steam control effectively, the process 
can be controlled so that gravity influences a flow of viscous fluids so 
as to maintain a pool of oil or hydrocarbonaceous fluids around a 
horizontal wellbore. 
Although the horizontal length of the wellbore can be modified as desired, 
as is preferred, the wellbore has a length of about 3,000 feet. 
Hydrocarbonaceous fluids within the reservoir include tar sands, asphalt, 
or other viscous hydrocarbonaceous fluids. Steam is allowed to circulate 
within the horizontal wellbore for a period of about 35 days or more. 
Steam injection into the reservoir is substantially avoided by maintaining 
a steam circulation rate in the range of about 100 barrels per day to 
about 200 barrels per day cold water equivalent (CWE) for about 35 days. 
As shown in FIGS. 1 and 2, steam 5 exits outer or upper compartment 2 by 
perforations 3. As the steam 5 and soluble gases exit perforations 3 into 
the formation or reservoir, some steam and vapor condense and begin to 
flow downwardly from steam zone 7 in said reservoir. Warmed oil of reduced 
viscosity 8 flows down and forms a pool 4 around the horizontal wellbore. 
As the warmed oil of reduced viscosity flows downwardly, both tangential 
and countercurrent flow of oil and vapor occur. As warmed oil 8 drains 
downwardly, a more easily vaporized fraction of the hydrocarbonaceous 
fluids is stripped off and rises upwardly along with steam and the gas 
soluble in hydrocarbonaceous fluids. This fraction dissolves in the oil at 
a steam and gas interface at the top edges of the steam zone and results 
in a further viscosity reduction of the hydrocarbonaceous fluids or oil. 
Since oil in the near wellbore region is warmed substantially by conduction 
heating, oil infill pressure gradients are much lower. As mentioned above, 
in U.S. Pat. No. 4,067,391 heating of the near wellbore region is expected 
to result in reduced sand production. Since the near wellbore region in 
the practice of this invention is heated to a much higher temperature due 
to steam circulation, higher inner wellbore temperatures are obtained, 
thus, reduced sand production is expected. 
Oil warmed by conduction in the near wellbore region flows under the 
influence of gravity into inner or lower compartment 1 along opening 9 
therein. Oil of reduced viscosity is brought to the surface by steam lift 
of the produced fluids. Thus, a continuous oil production process, aided 
by conduction heating in the near wellbore region, and driven by a gravity 
dominated steam zone, is obtained. 
While not desiring to be held to a particular theory, it is believed steam 
and the gases soluble in hydrocarbonaceous fluids circulate into the 
horizontal wellbore. Since the steam and gas have a small density relative 
to hydrocarbonaceous fluids in the formation, steam and gas tend to rise 
upwardly by gravity. Initially, as shown in FIG. 2, steam migration into 
the reservoir may be aided by mild pressure increases within outer or 
upper conduit 2. As steam moves upwardly in the reservoir, warmed oil 
drains downwardly both within and external to steam zone 7. Steam which 
passes out of upper perforations 3 forms a zone predominantly of steam and 
gas thereby making a vapor solvent 6. As the steam rises it liberates its 
heat by condensing at the upper portion of steam zone 7. Oil warmed by 
condensing steam and gas vapor drains downwardly through vapor solvent 
zone 6. As it drains, the lighter and more volatile portion of the 
hydrocarbonaceous fluids is stripped off. As steam and the solvent vapor 
rise through steam zone 7, a vapor solvent gradient is created due to 
collection of the non-condensible vapor at the surfaces of condensation 
along upper portion of steam zone 7. Warmed oil 8 flowing downwardly 
collects around the wellbore thereby forming pool 4. 
Since the process is forced into a gravity dominated mode by controlling 
steam production, oil 4 surrounds the wellbore instead of steam. A gravity 
head operates on oil pool 4 to provide a driving force for flow into 
opening 9 within lower or inner conduit 1. Oil within pool 4 thus flows 
into opening 9 and into inner or lower conduit 1. Oil, steam, and water 
are then brought to the surface by steam lifting imparted by the fluids. 
Oil flow into horizontal wellbore under the influence of conduction 
heating is made substantially easier. The following equation will aid in 
understanding the theory. 
This equation below can be derived for estimating the productivity, 
q.sub.o, of a well system where conduction aids oil inflow: 
##EQU1## 
Using this equation it is estimated that oil rates in the range of 0.12 
barrel per foot per day for a reservoir may be obtainable. Thus, a 2,000 
foot horizontal wellbore completed in the formation should have an oil 
rate of 240 barrels per day. This equation does not explicitly account for 
the gravity driving force, however, P.sub.e -P.sub.w may be thought of as 
the total driving force of pressure and gravity into the wellbore. 
Furthermore, due to the assumptions made, the equation may not apply to 
the process described herein in a direct manner. It only provides evidence 
of the enhanced effect on oil rate when conduction heating is present. 
In the operation of the preferred embodiment of this invention as shown in 
FIG. 2, production of steam is controlled by closing and opening control 
valve 10. If steam production becomes excessive, control valve 10 is 
choked back raising the pressure along the entire wellbore apparatus and 
preventing steam bypassing from the top slots to the bottom opening. 
Obviously, many other variations and modifications of this invention as 
previously set forth may be made without departing from the spirit and 
scope of this invention as those skilled in the art readily understand. 
Such variations and modifications are considered part of this invention 
and within the purview and scope of the appended claims.