Note: Descriptions are shown in the official language in which they were submitted.
CA 02363909 2006-07-17
77643-15
1
Upgrading and Recovery of Heavy Crude Oils
And Natural Bitumens by In Situ Hydrovisbreaking
Background of the Invention
Field of the Invention
This invention relates to a process for
simultaneously upgrading and recovering heavy crude oils and
natural bitumens from subsurface reservoirs.
Description of the Prior Art
Worldwide deposits of natural bitumens (also
referred to as "tar sands") and heavy crude oils are
estimated to total more than five times the amount of
remaining recoverable reserves of conventional crude
[References 1,51. But these resources (herein collectively
called "heavy hydrocarbons") frequently cannot be recovered
economically with current technology, due principally to the
high viscosities which they exhibit in the porous subsurface
formations where they are deposited. Since the rate at
which a fluid flows in a porous medium is inversely
proportional to the fluid's viscosity, very viscous
hydrocarbons lack the mobility required for economic
production rates.
Steam injection has been used for over 30 years to
produce heavy oil reservoirs economically by exploiting the
strong negative relationship between viscosity and
temperature that all liquid hydrocarbons exhibit. This
relationship is illustrated in the drawing labeled FIGURE 6,
which includes plots 601, 603, 605, and 607 of viscosity as
a function of temperature for heavy hydrocarbons from,
respectively, the Street Ranch, Saner Ranch, Athabasca, and
Midway Sunset deposits [Reference 6].
CA 02363909 2006-07-17
77643-15
la
In one method of steam-assisted production, steam
is injected into a formation through a borehole so that a
portion of the heavy oil in the formation is heated, thereby
significantly reducing its viscosity and increasing its
mobility. Steam injection is then halted and the oil is
produced through the same borehole. In a second method,
after the oil-bearing formation is preheated sufficiently by
steam injection into all boreholes, steam is continuously
injected into the
CA 02363909 2001-11-28
2
forma.tion through a set of injection boreholes to drive oil to a set of
production boreholes.
Referring again to FIG. 6, the plots show that heating the heavy hydrocarbons
from say
100 F, a typical temperature for the subsurface deposits in which the
hydrocarbons are found, to
400 F, a temperature that could be achieved in a subsurface deposit by
injecting steam from the
surface, reduces the viscosity of each of the four hydrocarbons by three to
four orders of
magnitude. Such viscosity reductions will not, however, necessarily result in
economic
production. The viscosity of Midway Sunset oil at 400 F approaches that of a
conventional
crude, which makes it economic to produce. But even at 400 F, the viscosities
of the bitumens
from Athabasca, Street Ranch, and Saner Ranch are 5.0 to 100 times greater
than the levels
required to ensure economic rates of recovery. Moreover, the high viscosities
of many heavy
hydrocarbons, when coupled with commonly encountered levels of formation
permeability, make
the injection of steam or other fluids which might be used for heating a
hydrocarbon-bearing
formation difficult or nearly impossible.
In addition to high viscosity, heavy hydrocarbons often exhibit other
deleterious properties
which cause their refining into marketable products to be a significant
challenge. These properties
are compared in Table 1 for an internationally-traded light crude, Arabian
Light, and three heavy
hydrocarbons.
Table I
Properties of Heavy Hydrocarbons Compared to a Light Crude
Light Crude Heavy Hydrocarbons
Properties Arabian Light Orinoco Cold Lake San Miguel
Gravity, API 34.5 8.2 11.4 -2 to 0
Viscosity, cp @ 100 F 10.5 7,000 10,700 >1,000,000
Sulfiu,wt% 1.7 3.8 4.3 7.9 to 9.0
Nitrogen, wt % 0.09 0.64 0.45 0.36 to 0.40
Metals, wppm 25 559 260 109
Bottoms (975 F +), vol % 15 59.5 51 71.5
Conradson carbon residue, wt % 4 16 13.1 24.5
CA 02363909 2001-11-28
3
The high levels of undesirable components found in the heavy hydrocarbons
shown in
Table 1, including sulfu.r, nitrogen, metals, and Conradson carbon residue,
coupled with a very
high bottoms yield, require costly refining processing to convert the heavy
hydrocarbons into
product streams suitable for the production of transportation fuels.
Two fundamental alternatives exist for the upgrading of heavy hydrocarbon
fractions:
carbon rejection and hydrogen addition.
~ Carbon-rejection schemes break apart (or "crack") carbon bonds in a heavy
hydrocarbon
fraction and isolate the resulting asphaltenes from the lighter fractions. As
the asphaltenes
have significantly higher carbon-to-hydrog.en ratios and higher concentrations
of
contaminants than the original feed, the product stream has a lower carbon-to-
hydrogen
ratio and significantly less contamination than the feed. Although less
expensive than
hydrogen-addition processes, carbon rejection has major disadvantages-
significant coke
production and low yields of liquid products which are of i.nferior quality.
~ Hydrogen-addition schemes convert unsaturated hydrocarbons to saturated
products and
high-molecular-weight hydrocarbons to hydrocarbons with lower molecular
weights while
removing contaminants without creating low-value coke. Hydrogen addition
thereby
provides a greater volume of total product than carbon rejection. The liquid
product yield
from hydrogen-addition processes can be 20 to 25 volume percent greater than
the yield
from processes employing carbon rejection. But these processes are expensive
to apply
and employ severe operating conditions. Catalytic hydrogenation, with reactor
residence
times of one to two hours, operate at temperatures in the 700 to 850 F range
with
hydrogen partial pressures of 1,000 to 3,000 psi.
Converting heavy crude oils and natural bitumens to upgraded liquid
hydrocarbons while
still in a subsurface formation, which is the object of the present invention,
would address the two
principal shortcomings of these heavy hydrocarbon resources-the high
viscosities which heavy
hydrocarbons exhibit even at elevated temperatures and the deleterious
properties which make it
necessary to subject them to costly, extensive upgrading operations after they
have been
produced. However, the process conditions employed in refinery units to
upgrade the quality of
CA 02363909 2001-11-28
4
liquid hydrocarbons would be extremely difficult to achieve in the subsurface.
The injection of
catalysts would be exceptionally expensive, the high temperatures used would
cause unwanted
coking in the absence of precise control of hydrogen partial pressures and
reaction residence time,
and the hydrogen partial pressures required could cause randoni, unintentional
fracturing of the
formation with a potential loss of control over the process.
A process occasionally used in the recovery of heavy crude oil and natural
bitumen which
to some degree converts in the subsurface heavy hydrocarbons to lighter
hydrocarbons is in situ
combustion. In this process an oxidizing fluid, usually air, is injected into
the hydrocarbon-
bearing formation at a sufficient temperature to initiate combustion of the
hydrocarbon. The heat
generated by the combustion warms other portions of the heavy hydrocarbon and
converts a part
of it to lighter hydrocarbons via uncatalyzed thermal cracking, which may
induce sufficient
mobility in the hydrocarbon to allow practical rates of recovery.
While in situ combustion is a relatively inexpensive process, it has major
drawbacks. The
high temperatures in the presence of oxygen which are encountered when the
process is applied
cause coke formation and the production of olefins and oxygenated compounds
such as phenols
and ketones, which in turn cause major problems when the produced liquids are
processed in
refinery units. Commonly, the processing of products from thermal cracking is
restricted to
delayed or fluid coking because the hydrocarbon is degraded to a degree that
precludes
processing by other methods.
The present invention concerns an in situ process which converts heavy
hydrocarbons to
lighter hydrocarbons that does not involve in situ combustion or the short
reaction residence
times, high temperatures, high hydrogen partial pressures, and catalysts which
are employed when
conversion reactions are conducted in refineries. Rather, conditions which can
readily be
achieved in hydrocarbon-bearing formations are utilized; viz., reaction
residence times on the
order of days to months, lower temperatures, lower hydrogen partial pressures,
and the absence
of injected catalysts. These conditions sustain what we designate as "in situ
hydrovisbreaking,"
conversion reactions within the formation which result in hydrocarbon
upgrading similar to that
achieved in refnery units through catalytic hydrogenation and hydrocracking.
The present
invention utilizes a unique combination of operations and associated hardware,
including the use
- _ - _ ~----_
- -------- ----
CA 02363909 2001-11-28
of a downhole combustion apparatus, to achieve hydrovisbreaking in formations
in which high-
viscosity hydrocarbons and conunonly encountered levels of formation
permeability combine to
limit fluid mobility.
Following is a review of the prior art as related to the operations
incorporated into this
invention. The patents referenced teach or suggest a means for enhancing flow
of heavy
hydrocarbons within a reservoir, the use of a downhole apparatus for in situ
operations,
procedures for effecting in situ conversion of heavy crudes and bitumens, and
methods for
recovering and processing the produced hydrocarbons.
In U.S. Patent 4,265,310, CONOCO patented the application of formation
fracturing to
steam recovery of heavy hydrocarbons.
Some of the best prior art disclosing the use of downhole devices for
secondary recovery
is found inU.S. Patents 4,159,743; 5,163,511; 4,865,130; 4,691,771; 4,199,024;
4,597,441;
3,982,591; 3,982,592; 4,024,912; 4,053,015; 4,050,515; 4,077,469; and
4,078,613. Other
expired patents which also disclose downhole generators for producing hot
gases or steam are
U.S. Patents 2,506,853; 2,584,606; 3,372,754; 3,456,721; 3,254,721; 2,887,160;
2,734,578; and
3,595,316.
The concept of separating produced secondary crude oil into hydrogen, lighter
oils, etc.
and the use of hydrogen for in situ combustion and downhole steaming
operations to recover
hydrocarbons are found in U.S. Patents 3,707,189; 3,908,762; 3,986,556;
3,990,513; 4,448,251;
4,476,927; 3,051,235; 3,084,919; 3,208,514; 3,327,782; 2,857,002; 4,444,257;
4,597,441;
4,241,790; 4,127,171; 3,102,588; 4,324,291; 4,099,568; 4,501,445; 3,598,182;
4,148,358;
4,186,800; 4,233,166; 4,284,139; 4,160,479; and 3,228,467. Additionally, in
situ hydrogenation
with hydrogen or a reducing gas is taught in U.S. Patents 5,145,003;
5,105,887; 5,054,551;
4,487,264; 4,284;139; 4,183,405; 4,160,479; 4,141,417; 3,617,471; and
3,228,467.
U.S. Patents 3,598,182 to Justheim; 3,327,782 to Hujsak; 4,448,251 to Stine;
4,501,445
to Gregoli; and 4,597,441 to Ware all teach variations of in situ
hydrogenation which more
closely resemble the current invention:
~ Justheirn, 3,327,782 modulates (heats or cools) hydrogen at the surface. In
order to
initiate the desired objectives of "distilling and hydrogenation" of the in
situ hydrocarbon,
CA 02363909 2001-11-28
6
hydrogen is heated on the surface for injection into the hydrocarbon-bearing
formation.
~ Hujsak, 4,448,251 teaches that hydrogen is obtained from a variety of
sources and
includes the heavy oil fractions from the produced oil which can be used as
reformer fuel.
Hujsak also includes and teaches the use of forward or reverse in situ
combustion as a
necessary step to effect the objectives of the process. Furthermore, heating
of the injected
gas or fluid is accomplished on the surface, an inefficient means of heating
compared to
using a downhole combustion unit because of heat losses incurred during
transportation of
the heated fluids to and down the borehole.
~ Stine, 4,448,251 utilizes a unique process which incorporates two adjacent,
non-
communicating reservoirs in which the heat or thermal energy used to raise the
formation
temperature is obtained from the adjacent reservoir. Stine utilizes in situ
combustion or
other methods to initiate the oil recovery process. Once reaction is achieved,
the desired
source of heat is from the adjacent zone.
~ Gregoli, 4,501,445 teaches that a crude formation is subjected to fracturing
to form "an
underground space suitable as a pressure reactor," in situ hydrogenation, and
conversion
utilizing hydrogen and/or a hydrogen donor solvent, recovery of the converted
and
produced crude, separation at the surface into various fractions, and
utilization of the
heavy residual fraction to produce hydrogen for re-injection. Heating of the
injected fluids
is accomplished on the surface which, as discussed above, is an inefficient
process.
~ Ware, 4,597,441 describes in situ "hydrogenation" (defined as the addition
of hydrogen to
the oil without cracking) and "hydrogenolysis" (defined as hydrogenation with
simultaneous cracking). Ware teaches the use of a downhole combustor.
Reference is
made to previous patents relating to a gas generator of the type disclosed in
U.S. Patents
3,982,591; 3,982,592; or 4,199,024. Ware further teaches and claims injection
from the
combustor of superheated steam and hydrogen to cause hydrogenation of
petroleum in
the formation. Ware also stipulates that after injecting superheated steain
and hydrogen,
sufficient pressure is maintained "to retain the hydrogen in the heated
formation zone in
contact with the petroleum therein for 'soaking' purposes for a period of
time." In some
embodiments Ware includes combustion of petroleurn products in the formation-a
major
CA 02363909 2006-07-17
77643-15
7
disadvantage, as discussed earlier--to drive fluids from the
injection to the production wells.
None of the patents referenced above teach the
application of fracturing or related methods to the
hydrocarbon-bearing formation for the purpose of enhancing
fluid mobility. In contrast, the Gregoli and Ware patents
both teach that injected fluids must be confined with the
in situ hydrocarbons to allow time for conversion reactions
to take place. Further, none of the patents referenced
include in situ conversion exclusively without combustion of
the hydrocarbon in the formation.
Another group of U.S. Patents--including 5,145,003
and 5,054,551 to Duerksen; 4,160,479 to Richardson;
4,284,139 to Sweany; 4,487,264 to Hyne; and 4,141,417 to
Schora--all teach variations of hydrogenation with heating
of the injected fluids (hydrogen, reducing gas, steam, etc.)
accomplished at the surface. Further, Schora, 4,141,417
injects hydrogen and carbon dioxide at a temperature of less
than 300 F and claims to reduce the hydrocarbon's viscosity
and accomplish desulfurization. Viscosity reduction is
assumed primarily through the well-known mechanism involving
solution of carbon dioxide in the hydrocarbon. None of
these patents includes the use of a downhole combustion unit
for injection of hot reducing gases.
In light of the current state of the technology,
what is needed--and what has been discovered by us--is an
efficient process for converting, and thereby upgrading,
very heavy hydrocarbons in situ without combustion of the
virgin hydrocarbon and the attendant degradation of products
which accompany combustion operations. The process
disclosed herein permits the production and utilization of
heavy-hydrocarbon resources which are otherwise not
CA 02363909 2006-07-17
77643-15
8
economically recoverable by other methods and minimizes the
amount of surface processing required to produce marketable
petroleum products.
Summary of the Invention
This invention provides a method for the in situ
upgrading and recovery of heavy crude oils and natural
bitumens. The process includes the heating of a targeted
portion of a formation containing heavy crude or bitumen
with steam and hot reducing gases to effect in situ
conversion reactions--including hydrogenation,
hydrocracking, desulfurization, and other reactions--
referred to collectively as hydrovisbreaking. Fracturing of
the subsurface formation or a related procedure is employed
to enhance injection of the required fluids and increase the
recovery rate of the upgraded hydrocarbons to an economic
level.
In this invention no combustion of the virgin
crude or bitumen occur in the formation so as to minimize
in situ degradation of the converted hydrocarbons. In the
instant invention, virgin hydrocarbons are only subjected to
reducing conditions after being heated by steam injection
and hot combustion gases. Formation hydrocarbons and
converted products are therefore never subjected to the
oxidation conditions encountered in conventional in situ
combustion operations, thereby eliminating the product
degradation which results from the formation of unstable
oxygenated components.
This invention utilizes a downhole combustion unit
to provide a thermally efficient process for the injection
of superheated steam and hot reducing gases adjacent to the
subsurface formation, thereby vastly reducing the heat
CA 02363909 2006-07-17
77643-15
9
losses inherent in conventional methods of subsurface
injection of hot fluids.
This invention eliminates much of the
capital-intensive conversion and upgrading facilities, such
as catalytic hydrocracking, that are required in
conventional processing of heavy hydrocarbons by upgrading
the hydrocarbons in situ.
This invention discloses a process for converting
heavy crude oils and natural bitumens in situ to lighter
hydrocarbons and recovering the converted materials for
further processing on the surface. The conversion
reactions--which may include hydrogenation, hydrocracking,
desulfurization, and other reactions--are referred to herein
as hydrovisbreaking. Continuous recovery utilizing one or
more injection boreholes and one or more production
boreholes, which may include multiple horizontal boreholes
extended from vertical boreholes, may be employed.
Alternatively, a cyclic method using one or more individual
boreholes, which may include multiple horizontal boreholes
extended from vertical boreholes, may be utilized.
The conditions necessary for sustaining the
hydrovisbreaking reactions are achieved by injecting
superheated steam and hot reducing gases, comprised
principally of hydrogen, to heat the formation to a
preferred temperature and to maintain a preferred level of
hydrogen partial pressure. This is accomplished through the
use of downhole combustion units, which are located in the
injection boreholes at a level adjacent to the heavy
hydrocarbon formation and in which hydrogen is combusted
with an oxidizing fluid while partially saturated steam and,
optionally, additional hydrogen are flowed from the surface
CA 02363909 2006-07-17
77643-15
to the downhole units to control the temperature of the
injected gases.
The method of this invention also includes the
creation of horizontal or vertical fractures to enhance the
5 injectibility of the steam and reducing gases and the
mobility of the hydrocarbons within the formation so that
the produced fluids are recovered at economic rates.
Alternatively, multiple horizontal boreholes extended from
vertical boreholes, a zone of either high water saturation
10 or high gas saturation in contact with the zone containing
the heavy hydrocarbon, or a pathway between wells created by
an essentially horizontal borehole may be utilized to
enhance inter-well communication.
Prior to its production from the subsurface
formation, the heavy hydrocarbon undergoes significant
conversion and resultant upgrading in which the viscosity of
the hydrocarbon is reduced by many orders of magnitude and
in which its API gravity may be increased by 10 to 15
degrees or more.
Following is a summary of the process steps for a
preferred embodiment to achieve this invention:
a. inserting downhole combustion units within
injection boreholes, which communicate with production
boreholes by means of horizontal fractures or by multiple
horizontal boreholes extended from the injection boreholes,
at or near the level of the subsurface formation containing
a heavy hydrocarbon;
b. for a first preheat period, flowing from the
surface through said injection boreholes stoichiometric
proportions of a reducing gas mixture and an oxidizing fluid
to said downhole combustion units and igniting same in said
CA 02363909 2006-07-17
77643-15
10a
downhole combustion units to produce hot combustion gases,
including superheated steam, while flowing partially
saturated steam from the surface through said injection
boreholes to said downhole combustion units to control the
temperature of said heated gases and to produce additional
superheated steam;
c. injecting said superheated steam into the
subsurface formation to heat a region of the subsurface
formation to a preferred temperature;
d. for a second conversion period, increasing the
ratio of reducing gas to oxidant in the mixture fed to the
downhole combustion units, or injecting reducing gas in the
fluid stream controlling the temperature of the combustion
units, to provide an excess of reducing gas in the hot gases
exiting the combustion units;
g. continuously injecting the heated excess
reducing gas and superheated steam into the subsurface
formation to provide preferred conditions and reactants to
sustain in situ hydrovisbreaking and thereby upgrade the
heavy hydrocarbon;
h. collecting continuously at the surface, from
said production boreholes, production fluids comprised of
converted liquid hydrocarbons, unconverted virgin heavy
hydrocarbons, residual reducing gases, hydrocarbon gases,
solids, water, hydrogen sulfide, and other components for
further processing.
In one aspect, the invention provides a process
for continuously converting, upgrading, and recovering heavy
hydrocarbons from a subsurface formation, said process being
free from the injection of hot oxidizing fluids into said
subsurface formation for the purpose of igniting a portion
CA 02363909 2006-07-17
77643-15
lOb
of said heavy hydrocarbons and being free of injection of
catalysts into the subsurface formation, and said process
comprising the steps of: a. inserting a downhole combustion
unit into at least one vertical injection borehole which
communicates with at least one production borehole by means
of multiple, uncased, horizontal boreholes extending from
the injection and production boreholes, said downhole
combustion unit being placed at a position within said
injection borehole in proximity to said subsurface
formation; b. flowing from the surface to said downhole
combustion unit within said injection borehole a set of
fluids--comprised of steam, reducing gases, and oxidizing
gases--and burning at least a portion of said reducing gases
with said oxidizing gases in said downhole combustion unit;
c. injecting a gas mixture--comprised of combustion products
from the burning of said reducing gases with said oxidizing
gases, residual reducing gases, and steam--from said
downhole combustion unit into said subsurface formation; d.
recovering from said production borehole, production fluids
comprised of said heavy hydrocarbons, which may be converted
to lighter hydrocarbons, as well as residual reducing gases,
and other components; e. continuing steps b, c, and d until
the recovery rate of said heavy hydrocarbons within said
subsurface formation in the region between said injection
borehole and said production borehole is reduced below a
level of practical operation.
In a further aspect, the invention provides a
process for cyclically converting, upgrading, and recovering
heavy hydrocarbons from a subsurface formation, said process
being free from the injection of hot oxidizing fluids into
said subsurface formation of the purpose of igniting a
portion of said heavy hydrocarbons and being free of
injection of catalysts into the subsurface formation, and
CA 02363909 2006-07-17
77643-15
lOc
said process comprising the steps of: a. inserting a
downhole combustion unit into at least one vertical
injection borehole in which multiple, uncased, horizontal
boreholes extend from the vertical borehole, said downhole
combustion unit being placed at a position within said
injection borehole in proximity to said subsurface
formation; b. for a first period, flowing from the surface
to said downhole combustion unit within said injection
borehole a set of fluids--comprised of steam, reducing
gases, and oxidizing gases--and burning at least a portion
of said reducing gases with said oxidizing gases in said
downhole combustion unit; c. injecting a gas mixture--
comprised of combustion products from the burning of said
reducing gases with said oxidizing gases, residual reducing
gases, and steam--from said downhole combustion unit into
said subsurface formation; d. for a second period, upon
achieving a preferred temperature within said subsurface
formation, halting injection of fluids into the subsurface
formation while maintaining pressure on said injection
borehole to allow time for a portion of said heavy
hydrocarbons in the subsurface formation to be converted
into lighter hydrocarbons; e. for a third period, reducing
the pressure on said injection borehole, in effect
converting the injection borehole into a production
borehole, and recovering at the surface production fluids,
comprised of said heavy hydrocarbons, which may be converted
to lighter hydrocarbons, as well as residual reducing gases,
and other components; f. repeating steps b through e to
expand the volume of said subsurface formation processed for
the recovery of said heavy hydrocarbons until the recovery
rate of said heavy hydrocarbons within said subsurface
formation in the vicinity of said injection borehole is
below a level of practical operation.
CA 02363909 2006-07-17
77643-15
lOd
Brief Description of the Drawings
FIG. 1 is a schematic of a preferred embodiment of
the invention in which injection boreholes and production
boreholes are utilized in a continuous fashion. Steam and
hot reducing gases from downhole combustion units in the
injection boreholes are flowed toward the production
boreholes where upgraded heavy hydrocarbons are collected
and produced.
FIG. 2 is a modification of FIG. 1 in which a
cyclic operating mode is illustrated whereby both the
injection and production operations occur in the same
borehole, with the recovery process operated as an injection
period followed by a production period. The cycle is then
CA 02363909 2001-11-28
11
repeated.
FIG. 3A is a plan view and FIG. 3B is a profile view of another embodiment
featuring the
use of horizontal boreholes. Injection of hot gases and steam is carried out
in vertical boreholes in
which vertical fractures have been created. The vertical fractures are
penetrated by one or more
horizontal production boreholes to efficiently collect the upgraded heavy
hydrocarbons.
FIG. 4 is a subterranean view of another embodiment featuring multiple,
uncased,
horizontal boreholes extended from vertical injection and production wells.
Injection of hot gases
and steam is carried out in the injection wells and upgraded heavy
hydrocarbons are collected in
the production wells, with communication between injection and production
wells enhanced by
the horizontal boreholes.
FIG. 5 is a plan view of a square production pattern showing an injection well
at the
center of the pattern and production wells at each of the corners. Contour
lines within the pattern
show the general distribution of injectants and temperature at a time midway
through the
production period.
FIG. 6 is a graph showing the recovery of oil in three cases A, B, and C using
the process
of the invention compared with a Base Case in which only steam was injected
into the reservoir.
The production patterns of the Base Case and of Cases A and B encompass 5
acres. The
production pattern of Case C encompasses 7.2 acres. FIG. 6 shows for the four
cases the
cumulative oil recovered as a percentage of the original oil in place (OOIP)
as a function of
production time.
FIG. 7 is a graph in which the viscosities of four heavy hydrocarbons are
plotted as a
function of temperature.
Description of the Preferred Embodiments
This invention discloses a process designed to upgrade and recover heavy
hydrocarbons
from subsurface formations which may not otherwise be economically recoverable
while
eliminating many of the deleterious and expensive features of the prior art.
The invention
CA 02363909 2006-07-17
77643-15
12
incorporates multiple steps including: (a) use of downhole
combustion units to provide a means for direct injection of
superheated steam and hot reactants into the hydrocarbon-
bearing formation; (b) enhancing injectibility and
inter-well communication within the formation via formation
fracturing or related methods; (c) in situ hydrovisbreaking
of the heavy hydrocarbons in the formation by establishing
suitable subsurface conditions via injection of superheated
steam and reducing gases; (d) production of the upgraded
hydrocarbons; (e) additional processing of the produced
hydrocarbons on the surface to produce marketable products.
The process of in situ hydrovisbreaking as
disclosed in this invention is designed to provide in situ
upgrading of heavy hydrocarbons comparable to that achieved
in surface units by modifying process conditions to those
achievable within a reservoir--relatively moderate
temperatures (625 to 750 F) and hydrogen partial pressures
(500 to 1,200 psi) combined with longer residence times
(several days to months) in the presence of naturally
occurring catalysts.
To effectively heat a heavy-hydrocarbon reservoir
to the minimum desired temperature of 625 F requires the
temperature of the injected fluid to be at least say 650 F,
which for saturated steam corresponds to a saturation
pressure of 2,200 psi. An injection pressure of this
magnitude could cause a loss of control over the process as
the parting pressure of heavy-hydrocarbon reservoirs, which
are typically found at depths of about 1,500 ft, is
generally less than 1,900 psi. Therefore, it is impractical
to heat a heavy-hydrocarbon reservoir to the desired
temperature using saturated steam alone. Use of
conventionally generated superheated steam is also
impractical because heat losses in surface piping and
CA 02363909 2006-07-17
77643-15
13
wellbores can cause steam-generation costs to be
prohibitively high.
The limitation on using steam generated at the
surface is overcome in this invention by use of a downhole
combustion unit, which can provide heat to the subsurface
formation in a more efficient manner. In its preferred
operating mode, hydrogen is combusted with oxygen with the
temperature of the combustion gases controlled by injecting
partially saturated steam, generated at the surface, as a
cooling medium. The superheated steam resulting from using
partially saturated steam to absorb the heat of combustion
in the combustion unit and the hot reducing gases exiting
the combustion unit are then injected into the formation to
provide the thermal energy and reactants required for the
process.
Alternately, a reducing-gas mixture--comprised
principally of hydrogen with lesser amounts of carbon
monoxide, carbon dioxide, and hydrocarbon gases--may be
substituted for the hydrogen sent to the downhole combustion
unit. A reducing-gas mixture has the benefit of requiring
less purification yet still provides a means of sustaining
the hydrovisbreaking reactions.
The downhole combustion unit is designed to
operate in two modes. In the first mode, which is utilized
for preheating the subsurface formation, the unit combusts
stoichiometric amounts of reducing gas and oxidizing fluid
so that the combustion products are principally superheated
steam. Partially saturated steam injected from the surface
as a coolant is also converted to superheated steam.
In a second operating mode, the amount of hydrogen
or reducing gas is increased beyond its stoichiometric
proportion (or the flow of oxidizing fluid is decreased) so
CA 02363909 2006-07-17
77643-15
14
that an excess of reducing gas is present in the combustion
products. Alternatively, hydrogen or reducing gas is
injected into the fluid stream controlling the temperature
of the combustion unit. This operation results in the
pressurizing of the heated subsurface region with hot
reducing gas. Steam may also be injected in this operating
mode to provide an injection mixture of steam and reducing
gas.
The downhole combustion unit may be of any design
which accomplishes the objectives stated above. Examples of
the type of downhole units which may be employed include
those described in U.S. Patents 3,982,591; 4,050,515;
4,597,441; and 4,865,130.
The downhole combustion unit may be designed to
operate in a conventional production well by utilizing an
annular configuration so that production tubing can extend
through the unit while it is installed downhole. With such
a design, fluids can be produced from a well containing the
unit without removing any equipment from the wellbore.
Instead of having the production tubing extending
through the unit, a gas generator of the type disclosed in
U.S. Patent Nos. 3,982,591 or 4,050,515 may be used for
heating the hydrocarbon formation and then removed from the
borehole to allow a separate production-tubing system to be
inserted into the borehole for production purposes.
Ignition of the combustible mixture formed in the
downhole combustion unit may be accomplished by any means
including the injection of a pyrophoric fluid with the fuel
gas to initiate combustion upon contact with the oxidant, as
described in U.S. Patent 5,163,511, or the use of an
CA 02363909 2006-07-17
77643-15
14a
electrical spark-generating device with electrical leads
extending from the surface to the downhole combustion unit.
The very high viscosities exhibited by heavy
hydrocarbons limit their mobility in the subsurface
formation and make it difficult to bring the injectants and
the in situ hydrocarbons into intimate contact so that they
may create the desired products. Solutions to this problem
may take several forms: (1) horizontally fractured wells,
(2) vertically fractured wells, (3) multiple horizontal
boreholes extended from vertical wells, (4) a zone of high
water saturation in contact with the zone containing the
heavy hydrocarbon, (5) a zone of high gas saturation in
contact with the zone containing the heavy hydrocarbon, or
(6) a pathway between wells created by an essentially
horizontal hole, such as established by Anderson, U.S.
Patents 4,037,658 and 3,994,340.
These configurations may be used in several ways.
Horizontal fractures may be used in a continuous mode of
injection and production which requires multiple wells--at
least one injector (preferably vertical) and at least one
producer (preferably vertical)--or in a cyclic mode with at
least one well (preferably vertical). Vertical fractures
may be used either in a continuous mode with at least one
injector (preferably vertical) and at least one producer
(preferably horizontal) or a cyclic mode with at least one
injector (preferably vertical). Horizontal boreholes
extended from vertical wells may be used in a continuous
mode of injection and production, which requires multiple
wells, or in a cyclic mode with at least one well.
When a zone of high water saturation is present in
contact with the zone containing a heavy hydrocarbon, its
presence is normally due to geological processes.
CA 02363909 2006-07-17
77643-15
14b
Therefore, not all formations containing heavy hydrocarbons
are in contact with a zone of high water saturation.
Doscher, U.S. Patent 3,279,538, showed how to inject steam
into such a water-saturated zone to establish communication
between multiple wells in heavy oil reservoirs. In such a
case, and also in the case of horizontal fractures used in
the continuous mode, it is important to inject the hot fluid
rapidly enough to establish a heated zone which completely
extends between at least two wells. Failure to establish a
heated zone can allow displaced, heated, heavy oil to
migrate into the flow path (i.e., the fracture or the water
zone), lose heat, thereby become more viscous, and halt the
recovery process. The injection into a water-saturated zone
can be used either in the continuous or cyclic mode.
CA 02363909 2001-11-28
A zone of high gas saturation in contact with the zone containing a heavy
hydrocarbon
also provides a conduit for flow between wells. Sceptre Resources Ltd.
successfully used steam
injection into a gas cap in the Tangleflags Field in Saskatchewan to recover
the heavy oil
underlying a gas zone. A similar procedure would be possible with the in situ
hydrovisbreaking
process that is the subject of the present invention. In this case, the
location of the gas zone
above the heavy hydrocarbon might lessen the efficiency of the mixing of
reactants, several of
which are in the gas phase, but its high level of communication might more
than offset this
problem. Injection into a gas zone will probably only be efficient in the
continuous mode of
operation.
Anderson, 4,037,658 and 3,994,340, patented processes for establishing
communication
between two wells by drilling an essentially horizontal hole connecting the
wells that is separated
from the surrounding formation by casing. One of the wells serves as a point
of injection, while
the other serves as a point of production. At the beginning of the recovery
process, steam is
injected into the injection well and flows into the horizontal casing, which
is not perforated except
at the end near the producing well. The passage of steam through the
horizontal pipe heats the
surrounding formation by conduction to the point where the viscosity of the
heavy hydrocarbon in
the formation drops low enough to permit it to flow under typical injection
pressures. Then, hot
reaction gases are injected into the formation at the bottom of the injection
well. Since the heavy
hydrocarbon is now mobile, the injectants are able to displace heavy
hydrocarbon into the
producing well through the heated annulus that surrounds the hot, horizontal
pipe. In time the
heated zone grows larger, sustainuzg itself from the hot injected fluids and
the exothermic
reactions that have been initiated, and no longer requires heat from inside
the horizontal pipe.
A significant disclosure of this invention is that use of fractures within the
subsurface
formation or the other related methods just discussed are consistent with
controlling the injection
of fluids into the reaction zone. As illustrated in a following example,
creating fractures in a
reservoir can significantly enhance the rate of fluid injection and the degree
of fluid mobility
within a heavy-hydrocarbon formation resulting in greatly increased recovery
of converted
hydrocarbons.
The steps necessary to provide the conditions required for the in situ
hydrovisbreaking
CA 02363909 2006-07-17
77643-15
16
reactions to occur may be implemented in a continuous mode,
a cyclic mode, or a combination of these modes. The process
may include the use of conventional vertical boreholes,
horizontal boreholes, or vertical boreholes with multiple
horizontal extensions. Any method known to those skilled in
the art of reservoir engineering and hydrocarbon production
may be utilized to effect the desired process within the
required operating parameters.
In the continuous operating mode, a number of
boreholes are utilized for injection of steam and hot
reducing gases. The injected gases flow through the
subsurface formation, contact and react with the in situ
hydrocarbons, and are recovered along with the upgraded
hydrocarbons in a series of production boreholes. The
injection and production boreholes may be arranged in any
pattern amenable to the efficient recovery of the upgraded
hydrocarbons. The rate of withdrawal of fluids from the
production boreholes may be adjusted to control the pressure
and the distribution of gases within the subsurface
formation.
In the cyclic operating mode, multiple boreholes
are operated independently in a cyclic fashion consisting of
a series of injection and production periods. In the
initial injection period, steam and hot reducing gases are
injected into the region adjacent to the wellbore. After a
period of soaking to allow conversion reactions to occur,
the pressure on the wellbore is reduced and upgraded
hydrocarbons are recovered during a production period. In
subsequent cycles, this pattern of injection and production
is repeated with an increasing extension into the subsurface
formation.
CA 02363909 2006-07-17
77643-15
17
A hybrid operating mode is also disclosed in which
the subsurface formation is first treated using a series of
boreholes employing the cyclic mode just described. After
this mode is used to the limit of practical operation, a
portion of the injection boreholes are converted to
production boreholes and the process is operated in a
continuous mode to recover additional hydrocarbons bypassed
during the cyclic operation.
After completion of any of the procedures outlined
above for recovery of upgraded hydrocarbons, it may be
beneficial to utilize surfactants (surface active agents
such as soap) which have been found to enhance oil recovery
from steam-injection processes. These will also aid in oil
recovery for the process of this invention. High-
temperature surfactants (surfactants which retain their
function at high temperatures) may be injected during the
period of the operation in which the temperature of the
injected fluids is less than the limit at which they are
effective. Similarly, low-temperature surfactants--which
include sodium hydroxide, potassium hydroxide, potassium
carbonate, potassium orthosilicate, and other similar high-
pH, inorganic compounds--may be injected. These surfactants
react with the naturally occurring carboxylic acids in the
in situ hydrocarbons to form natural surfactants, which will
have beneficial effects on recovery of heavy hydrocarbons.
These surfactants will be injected in a late stage of the
process during the implementation of a clean-up, or
scavenging phase. This phase will take advantage of the
injection of cold or warm water to transport heat from areas
depleted in heavy hydrocarbons to other undepleted areas,
and the injected surfactants will aid in scavenging the
remaining hydrocarbons.
CA 02363909 2006-07-17
77643-15
18
Operation of the in situ hydrovisbreaking process
will be controlled utilizing available physical
measurements. Controllable elements include the injection
pressure, injection rate, temperature, and fluid
compositions of the injected gases. In addition, the back-
pressure maintained on production boreholes may be selected
to control the distribution of production rates among
various boreholes. Measurements may be taken at the
injection boreholes, production boreholes, and observation
wells within the production patterns. All of this
information can be gathered and processed, either manually
or by computer, to obtain the optimum degree of conversion,
product quality, and recovery level of the hydrocarbon
liquids being collected.
Referring to the drawing labeled FIG. 1, there is
illustrated a borehole 21 for an injection well drilled from
the surface of the earth 199 into a hydrocarbon-bearing
formation or reservoir 27. The injection-well borehole 21
is lined with steel casing 29 and has a wellhead control
system 31 atop the well to regulate the flow of reducing
gas, oxidizing fluid, and steam to a downhole combustion
unit 206. The casing 29 contains perforations 200 to
provide fluid communication between the inside of the
borehole 21 and the reservoir 27.
Also in FIG. 1, there is illustrated a borehole
201 for a production well drilled from the surface of the
earth 199 into the reservoir 27 in the vicinity of the
injection-well borehole 21. The production-well
borehole 201 is lined with steel casing 202. The casing 202
contains perforations 203 to provide fluid communication
between the inside of the borehole 201 and the reservoir 27.
Fluid communication with the reservoir 27 between the
injection-well borehole 21 and the production-well
CA 02363909 2006-07-17
77643-15
18a
borehole 201 is enhanced by hydraulically fracturing the
reservoir in such a manner as to introduce a horizontal
fracture 204 between the two boreholes.
Of interest is to inject hot gases into the
reservoir 27 by way of the injection-well borehole 21 and
continuously recover hydrocarbon products from the
production-well borehole 201. Referring again to FIG. 1,
three fluids under pressure are coupled to the wellhead
control system 31: a source of reducing gas by line 81, a
source of oxidizing-fluid by line 91, and a source of
cooling-fluid by line 101. Through injection tubing strings
205, the three fluids are coupled to the downhole combustion
unit 206. The fuel is oxidized by the oxidizing fluid in
the combustion unit 206, which is cooled by the cooling
fluid. The products of oxidation and the cooling fluid 209
along with any un-oxidized fuel 210, all of which are heated
by the exothermic oxidizing reaction, are injected into the
horizontal fracture 204 in the reservoir 27 through the
perforations 200 in the casing 29. Heavy hydrocarbons 207
in the reservoir 27 are heated by the hot injected fluids
which, in the presence of hydrogen, initiate
hydrovisbreaking reactions. These reactions upgrade the
quality of the hydrocarbons by converting their higher
molecular-weight components into lower molecular-weight
components which have less density, lower viscosity, and
greater mobility within the reservoir than the unconverted
hydrocarbons. The hydrocarbons subjected to the
hydrovisbreaking reactions and additional virgin
hydrocarbons flow into the perforations 203 of the
casing 202 of the production-well borehole 201, propelled by
the pressure of the injected fluids. The hydrocarbons and
injected fluids arriving at the production-well borehole 201
are removed from the borehole using conventional oil-field
CA 02363909 2006-07-17
77643-15
18b
technology and flow through production tubing strings 208
into the surface facilities. Any number of injection wells
and production wells may be operated simultaneously while
situated so as to allow the injected fluids to flow
efficiently from the injection wells through the reservoir
to the production wells contacting a significant portion of
the heavy hydrocarbons in situ.
In the preferred embodiment, the cooling fluid is
steam, the reducing gas is hydrogen, and the oxidizing fluid
used is oxygen, whereby the product of oxidation in the
downhole combustion unit 206 is superheated steam. This
unit incorporates a combustion chamber in which the hydrogen
and oxygen mix and react. Preferably, a stoichiometric
mixture of hydrogen and
CA 02363909 2001-11-28
19
oxygen is initially fed to the unit during its operation. This mixture has an
adiabatic flame
temperature of approximately 5,700 F and must be cooled by the coolant steam
in order to
protect the combustion unit's materials of construction. After cooling the
downhole combustion
unit, the coolant steam is mixed with the combustion products, resulting in
superheated steam
being injected into the reservoir. Generating steam at the surface and
injecting it to cool the
downhole combustion unit reduces the amount of hydrogen and oxygen, and
thereby the cost,
required to produce a given amount of heat in the form of superheated stearn.
The coolant steam
may include liquid water as the result of injection at the surface or
condensation within the
injection tubing. The ratio of the mass flow of steam passing through the
injection tubing 205 to
the mass flow of oxidized gases leaving the combustion unit 206 affects the
temperature at which
the superheated steam is injected into the reservoir 27. As the reservoir
becomes heated to the
level necessary for the occurrence of hydrovisbreaking reactions, it is
preferable that a
stoichiometric excess of hydrogen be fed to the downhole combustion unit
during its
operation-or that hydrogen be injected into the fluid stream controlling the
temperature of the
combustion unit-resulting in hot hydrogen being injected into the reservoir
along with
superheated steam. This provides a continued heating of the reservoir in the
presence of
hydrogen, which are the conditions necessary to sustain the hydrovisbreaking
reactions.
In another embodiment, a reducing-gas mixture-comprised principally of
hydrogen with
lesser amounts of carbon monoxide, carbon dioxide, and hydrocarbon gases-may
be substituted
for hydrogen. Such a mixture has the benefit of requiring less purification
yet still provides a
means of sustaining the hydrovisbreaking reactions.
FIG. 1 therefore shows a hydrocarbon-production system that continuously
converts,
upgrades, and recovers heavy hydrocarbons from a subsurface formation
traversed by one or
more injection boreholes and one or more production boreholes with inter-well
communication
established between the injection and production boreholes. The system is free
from any
combustion operations within the subsurface formation and free from the
injection of any
oxidizing materials or catalysts.
Referring to the drawing labeled FIG. 2, there is illustrated a borehole 21
for a well drilled
from the surface of the earth 199 into a hydrocarbon-bearing formation or
reservoir 27. The
CA 02363909 2001-11-28
borehole 21 is lined with steel casing 29 and has a wellhead control system 31
atop the well. The
casing 29 contains perforations 200 to provide fluid communication between the
inside of the
borehole 21 and the reservoir 27. The ability of the reservoir to accept
injected fluids is enhanced
by hydraulically fracturing the reservoir to create a horizontal fracture 204
in the vicinity of the
borehole 21.
Of interest is to cyclically inject hot gases into the reservoir 27 by way of
the borehole 21
and subsequently to recover hydrocarbon products from the same borehole.
Referring again to
FIG. 2, three fluids under pressure are coupled to the wellhead control system
3 1: a source of
reducing gas by line 81, a source of oxidizing-fluid by line 91, and a source
of cooling-fluid by line
101. Through injection tubing strings 205, the three fluids are coupled to a
downhole
combustion unit 206. The combustion unit is of an annular configuration so
tubing strings can be
run through the unit when it is in place downhole. During the injection phase
of the process, the
fuel is oxidized by the oxidizing fluid in the combustion unit 206, which is
cooled by the cooling
fluid in order to protect the combustion unit's materials of construction. The
products of
oxidation and the cooling fluid 209 along with any un-oxidized fuel 210, all
of which are heated
by the exothermic oxidizing reaction, are injected into the horizontal
fracture 204 in the reservoir
27 through the perforations 200 in the casing 29. As in the continuous-
production process, heavy
hydrocarbons 207 in the reservoir 27 are heated by the hot injected fluids
which, in the presence
of hydrogen, initiate hydrovisbreaking reactions. These reactions upgrade the
quality of the
hydrocarbons by converting their higher molecular-weight components into lower
molecular-
weight components which have less density, lower viscosity, and greater
mobility within the
reservoir than the unconverted hydrocarbons. At the conclusion of the
injection phase of the
process, the injection of fluids is suspended. Afler a suitable amount of time
has elapsed, the
production phase begins with the pressure at the wellhead 31 reduced so that
the pressure in the
reservoir 27 in the vicinity of the borehole 21 is higher than the pressure at
the wellhead. The
hydrocarbons subjected to the hydrovisbreaking reactions, additional virgin
hydrocarbons, and the
injected fluids flow into the perforations 200 of the casing 29 of the
borehole 21, propelled by the
excess reservoir pressure in the vicinity of the borehole. The hydrocarbons
and injected fluids
arriving at the borehole 21 are removed from the borehole using conventional
oil-field technology
CA 02363909 2006-07-17
77643-15
21
and flow through production tubing strings 208 into the
surface facilities. Any number of wells may be operated
simultaneously in a cyclic fashion while situated so as to
allow the injected fluids to flow efficiently through the
reservoir to contact a significant portion of the heavy
hydrocarbons in situ.
As with the continuous-production process
illustrated in FIG. 1, in the preferred embodiment the
cooling fluid is steam, the fuel used is hydrogen, and the
oxidizing fluid used is oxygen. Preferably, a
stoichiometric mixture of hydrogen and oxygen is initially
fed to the downhole combustion unit 206 so that the sole
product of combustion is superheated steam. As the
reservoir becomes heated to the level necessary for the
occurrence of hydrovisbreaking reactions, it is preferable
that a stoichiometric excess of hydrogen be fed to the
downhole combustion unit during its operation--or that
hydrogen be injected into the fluid stream controlling the
temperature of the combustion unit--resulting in hot
hydrogen being injected into the reservoir along with
superheated steam. This provides a continued heating of the
reservoir in the presence of hydrogen, which is the
condition necessary to sustain the hydrovisbreaking
reactions.
As with the continuous-production process, in
another embodiment of the cyclic process a reducing-gas
mixture--comprised principally of hydrogen with lesser
amounts of carbon monoxide, carbon dioxide, and hydrocarbon
gases--may be substituted for hydrogen.
FIG. 2 therefore shows a hydrocarbon-production
system that cyclically converts, upgrades, and recovers
heavy hydrocarbons from a subsurface formation traversed by
CA 02363909 2006-07-17
77643-15
22
one or more boreholes which have been fractured to enhance
injectivity and mobility of fluids within the formation.
The system is free from any combustion operations within the
subsurface formation and free from the injection of any
oxidizing materials or catalysts.
In yet another embodiment, horizontal well
technology is applied to the process of this invention.
This method is illustrated in FIG. 3, in which FIG. 3A shows
a plan view and FIG. 3B which shows a profile view, of one
configuration for combining vertical injection wells with
horizontal production wells. There is illustrated in FIG.
3B a borehole 21 for an injection well drilled from the
surface of the earth 199 into a hydrocarbon-bearing
formation or reservoir 27. The borehole is lined with steel
casing 29 and has a wellhead control system 31 atop the
well. The casing 29 contains perforations 200 to provide
communication between the inside of the borehole 21 and the
reservoir 27. The injection well borehole 21 is
hydraulically fractured to create a vertical fracture 211.
In the plan view of FIG. 3, there are illustrated horizontal
production wells 212 with casing that is slotted to
communicate with the reservoir 27. The horizontal wells are
drilled so as to intersect the vertical fractures 211 of the
injection wells.
It is of interest to inject hot gases into the
reservoir 27 by way of one or more injection-well boreholes
and continuously recover hydrocarbon products from one or
more horizontal production wells. The wellhead control
system 31 used to regulate the flow of injected fluids on
each of the injection wells is supplied with a fuel source
by line 81, an oxidizing fluid by line 91, and a cooling
fluid by line 101. Through injection tubing strings 205,
the three fluids are coupled to a downhole combustion
CA 02363909 2006-07-17
77643-15
23
unit 206. The fuel is oxidized in the combustion unit 206,
which is cooled by the cooling fluid in order to protect the
combustion unit's materials of construction. The products
of oxidation and the cooling fluid 209 along with an
un-oxidized fuel 210, all of which are heated by the
exothermic oxidizing reaction, are injected into the
reservoir 27 through the perforations 200 in the casing 29.
Heavy hydrocarbons 207 in the reservoir 27 are heated by the
hot injected fluids which, in the presence of hydrogen,
initiate hydrovisbreaking reactions. These reactions
upgrade the quality of the hydrocarbons by converting their
higher molecular-weight components into lower molecular-
weight components which have less density, lower viscosity,
and greater mobility within the reservoir than the
unconverted hydrocarbons. The hydrocarbons subjected to the
hydrovisbreaking reactions and additional virgin
hydrocarbons, propelled by the pressure of the injected
fluids, flow into the vertical fractures 211 of the
reservoir 27 and thence into the horizontal producing wells
intersecting the fractures, where they are recovered along
with the injected fluids using conventional oil-field
technology.
FIG. 3 therefore shows a hydrocarbon-recovery
system that continuously converts, upgrades, and recovers
heavy hydrocarbons from a subsurface formation traversed by
one or more vertical wells--used for injection--and by one
or more horizontal wells--used for production--which are
drilled within the reservoir containing the hydrocarbons.
The injection wells may be vertically fractured and the
horizontal wells drilled so as to intersect the fractures.
In another embodiment, multiple horizontal
boreholes--extended from one or more vertical injection
wells and from one or more vertical production wells--are
CA 02363909 2006-07-17
77643-15
23a
employed in a continuous-production process. This method is
illustrated in FIG. 4, in which uncased, horizontal
boreholes 213 are extended within a reservoir from one or
more vertical injection well boreholes 21 that are equipped
as in FIG. 1, and uncased, horizontal boreholes 214 are
extended within the same reservoir from vertical production
well boreholes 201 that are also equipped as in FIG. 1.
Fluid communication within the reservoir between the
injection well boreholes 21 and the production well
boreholes 201 is enhanced by the boreholes extended from the
wells.
As in the continuous-production process described
previously, it is of interest to inject hot gases into the
reservoir by way of one or more injection wells and
continuously recover hydrocarbon products from one or more
production wells. Previously-described hot gases are
injected into the reservoir through the horizontal boreholes
of one or more injection wells. Heavy hydrocarbons 207 in
the reservoir are heated by the hot injected fluids which,
in the presence of hydrogen, initiate hydrovisbreaking
reactions. These reactions upgrade the quality of the
hydrocarbons by converting their higher molecular-weight
components into lower molecular-weight components which have
less density, lower viscosity, and greater mobility within
the reservoir than the unconverted hydrocarbons. The
hydrocarbons subjected to the hydrovisbreaking reactions and
additional virgin hydrocarbons, propelled by the pressure of
the injected fluids, flow into the horizontal boreholes of
one or more producing wells, where they are recovered along
with the injected fluids using conventional oil-field
technology.
FIG. 4 therefore shows the subterranean portion of
a hydrocarbon-recovery system that continuously converts,
CA 02363909 2006-07-17
77643-15
23b
upgrades, and recovers heavy hydrocarbons from a subsurface
formation traversed by one or more vertical injection wells
having multiple, uncased, horizontal-borehole extensions and
by one or more vertical production wells having multiple,
uncased, horizontal-borehole extensions which are drilled
within the reservoir containing the hydrocarbons.
In yet another embodiment, multiple, horizontal
boreholes--extended from one or more vertical wells--are
employed in a cyclic-production process. The process is
identical to the cyclic-production process previously
described except that the ability of the hydrocarbon
reservoir to accept injected fluids is enhanced by extending
multiple, uncased, horizontal boreholes from the vertical
wells into the reservoir instead of initiating in the
vertical wells horizontal fractures that
CA 02363909 2001-11-28
24
extend into the reservoir.
Example I
Hydrovisbreaking Upgrades Many Heavy Crudes and Bitumens
Example I illustrates the upgrading of a wide range of heavy hydrocarbons that
can be
achieved through hydrovisbreaking, as confirmed by bench-scale tests.
Hydrovisbreaking tests
were conducted by World Energy Systems on four heavy crude oils and five
natural bitumens
[Reference 8]. Each sample tested was charged to a pressure vessel and allowed
to soak in a
hydrogen atmosphere at a constant pressure and temperature. In all cases,
pressure was
maintained below the parting pressure of the reservoir from which the
hydrocarbon sample was
obtained. Temperature and hydrogen soak times were varied to obtain
satisfactory results, but no
attempt was made to optirnize process conditions for the individual samples.
Table 2 lists the process conditions of the tests and the physical properties
of the heavy
hydrocarbons before and after the application of hydrovisbreaking. As shown in
Table 2,
hydrovisbreaking caused exceptional reductions in viscosity and significant
reductions in
molecular weight (as indicated by API gravity) in all samples tested.
Calculated atomic
carbon/hydrogen (C/H) ratios were also reduced in all cases.
In most cases the results shown in Table 2 are from single runs, except for
the San Miguel
results which are the averages of seven runs. From the multiple San Miguel
runs, data
uncertainties expressed as standard deviation of a single result were found to
be 21 cp for
viscosity, 3.3 API degrees for gravity, 0.5 wt % for sulfur content, and 0.43
for C/H ratio.
Comparing these levels of uncertainty with the magnitude of the values
measured, it is clear that
the improvements in product quality from hydrovisbreaking listed in Table 2
are statistically
significant even though the conditions under which these experiments were
conducted are at the
lower end of the range of conditions specified for this invention, especially
with regards to
temperature and reaction residence time.
CA 02363909 2001-11-28
Table 2
Conditions and Results from Hydrovisbreaking Tests on Heavy Hydrocarbons
(Example I)
Asphalt Tar Sands
Crude/Bitumen Kern River Unknown San Miguel Slocum Ridge Trian le Athabasca
Cold Lake Primrose
Location Calitomia California Texas Texas Utah Utah Alberta Alberta Alberta
Test Conditions
Temperature, F 650 625 650 700 650 650 650 650 600
H2 Pressure, psi 1,000 2,000 1,000 1,000 900 1,000 1,000 1,500 1,000
Soak Time, da s 10 14 11 7 8 10 3 2 9
Properties Before and After H drovisbreakin Tests
Viscosity, cp(@
Before 3,695 81,900 >1,000,000 1,379 1,070 700,000 100,000 10,700 11,472
After 31 1,000 55 6 89 77 233 233 220
Ratio 112 82 18,000 246 289 9,090 429 486 52
Gravity, API
Before 13 7 0 16.3 12.8 8.7 6.8 9.9 10.6
After 18.6 12.5 10.7 23.7 15.4 15.3 17.9 19.7 14.8
Increase 6.0 5.5 10.7 7.4 2.6 6.6 11.1 9.8 3.8
Sulfur, wt %
Before 1.2 1.5 7.9 0.3 0.4 3.8 3.9 4.7 3.6
After 0.9 1.3 4.8 0.2 0.4 2.5 2.8 2.2 3.8
%Reduction 29 13 38 33 0 35 29 53 0
Carbon/H dro en Ratio, wt/wt
Before 7.5 7.8 9.8 8.3 7.2 8.1 7.9 7.6 8.8
After 7.4 7.8 8.5 7.6 7.0 8.0 7.6 N/A 7.3
Example II
Hydrovisbreaking Increases Yield of
Upgraded Hydrocarbons Compared to Conventional Thermal Cracking
Example II illustrates the advantage of hydrovisbreaking over conventional
thermal
cracking. During the thermal cracking of heavy hydrocarbons coke formation is
suppressed and
the yield of light hydrocarbons is increased in the presence of hydrogen, as
is the case in the
hydrovisbreaking process.
The National Institute of Petroleum and Energy Research conducted bench-scale
CA 02363909 2001-11-28
26
experiments on the thermal cracking of heavy hydrocarbons [Reference 7]. One
test on heavy
crude oil from the Cat Canyon reservoir incorporated approximately the
reservoir conditions and
process conditions of in situ hydrovisbreaking. A second test was conducted
under nearly
identical conditions except that nitrogen was substituted for hydrogen.
Test conditions and results are summarized in Table 3. The hydrogen partial
pressure at
the beginning of the experiment was 1,064 psi. As hydrogen was consumed
without
replenishment, the average hydrogen partial pressure during the experiment is
not known with
total accuracy but would have been less than the initial partial pressure. The
experiment's
residence time of 72 hours is at the low end of the range for in situ
hydrovisbreaking, which might
be applied for residence times more than 100 times longer.
Table 3
Thermal Cracking of a Heavy Crude Oil in the Presence and Absence of Hydrogen
(Example II)
Gas Atmosphere Hydrogen Nitrogen
Pressure cylinder charge, grams
Sand 500 500
Water 24 24
Heavy crude oil 501 500
Process conditions
Residence time, hours 72 72
Temperature, F 650 650
Total pressure, psi 2,003 1,990
Gas partial pressure, psi 1,064 1,092
Products, grams
Light (thermally cracked) oil 306 208
Heavy oil 148 152
Residual carbon (coke) 8 30
Gas (by difference) 39 110
CA 02363909 2001-11-28
27
Although operating conditions were not as severe in terms of residence time as
are desired
for in situ hydrovisbreaking, the yield of light oil processed in the hydrogen
atmosphere was
almost 50% greater than the light oil yield in the nitrogen atmosphere,
illustrating the benefit of
hydrovisbreaking (i.e., non-catalytic thermal cracking in the presence of
significant hydrogen
partial pressure) in generating light hydrocarbons from heavy hydrocarbons.
Example III
Commercial-Scale Application of In Situ Hydrovisbreaking
Example III indicates the viability of in situ hydrovisbreaking when applied
on a
commercial scale. The continuous recovery of commercial quantities of San
Miguel bitumen is
considered.
Bench-scale experiments and computer simulations of the application of in situ
hydrovis-
breaking to San Miguel bitumen suggest recoveries of about 80% can be
realized. The bench-
scale experiments referenced in Example II include tests on San Miguel bitumen
where an overall
liquid hydrocarbon recovery of 79% was achieved, of which 77% was thermally
cracked oil.
Computer modeling of in situ hydrovisbreaking of San Miguel bitumen (described
in Example IV
following) predict recoveries after one year's operation of 88 to 90% within
inverted 5-spot
production patterns of 5 and 7.2 acres [Reference 3].
At a recovery level of 80%, at least 235,000 barrels (Bbl) of hydrocarbon can
be produced
from a 7.2-acre production pattern in the San Miguel bitumen formation.
Assuming the produced
hydrocarbon serves as the source of hydrogen, oxygen, and steam for the
process, energy and
material balances indicate that 103,500 Bbl of the produced hydrocarbon would
be consumed in
the production of process injectants. (The balances are based on the
fractionation of the produced
hydrocarbon into a synthetic crude oil and a residuum stream. The residuum is
used as feed to a
partial oxidation unit, which produces hydrogen for the process as well as
fuel gas for a steam
plant and for generation of the electricity used in an oxygen plant.) Thus,
each production pattern
would provide 131,500 Bbl of net production in one year, or about 45% of the
hydrocarbon
originally in place, at an average production rate of 360 barrels per day
(Bbl/d).
CA 02363909 2001-11-28
28
These calculations provide a basis for the design of a commercial level of
operation in
which fifty 7.2-acre production patterns, each with the equivalent of one
injection well and one
production well, are operated simultaneously. Together, the 50 patterns would
provide gross
production averaging 32,000 Bbl/d, which-after surface processing-would
generate synthetic
crude oil with a gravity of approximately 25 API at the rate of 18,000 Bbl/d.
As the projected
life of each production pattern is one year, all injection wells and all
production wells in the
pattezns would be replaced annually.
Field tests [References 2,6] and computer simulations [Reference 3] indicate a
similar
sized operation using steamflooding instead of in situ hydrovisbreaking would
produce 20,000
Bbl/d of gross production, some three-quarters of which would be consumed at
the surface in
steam generation, providing net production of 5,000 Bbl/d of a liquid
hydrocarbon having an API
gravity of about 10 .
FIG. 5 shows the general distribution across a nominal 5 to 7-acre production
pattern of
the injectants and of the temperature within the formation at a time midway
through the
production period. The contours within the production pattern in FIG. 5 are
based on the results
of computer simulations of in situ hydrovisbreaking of the San Miguel bitumen
discussed below in
Examples IV and V.
Example IV
In Situ Hydrovisbreaking Promoted by Formation Fracturing
Example IV illustrates how formation fracturing makes possible the injection
of
superheated steam and a reducing gas into a formation containing a very
viscous hydrocarbon,
thereby promoting in situ hydrovisbreaking of the hydrocarbon. In situ
hydrovisbreaking,
conducted in the absence of fracturing, is compared through computer
simulation to in situ
hydrovisbreaking conducted with horizontal fractures introduced prior to
injecting any fluids.
A comprehensive, three-dimensional reservoir simulation model was used to
conduct the
simulations discussed in this and the following examples. The model solves
simultaneously a set
CA 02363909 2001-11-28
29
of convective mass transfer, convective and conductive heat transfer, and
chemical-reaction
equations applied to a set of grid blocks representing the reservoir. In the
course of a simulation,
the model rigorously maintains an accounting of the mass and energy entering
and leaving each
grid block. Any number of components may be included in the model, as well as
any number of
chemical reactions between the components. Each chemical reaction is described
by its
stoichiometry and reaction rates; equilibria are described by appropriate
equilibrium
thermodynamic data.
Reservoir properties of the San Miguel bitumen formation, obtained from
Reference 6,
were used in the inodel. Chemical reaction data in the model were based on the
bench-scale
hydrovisbreaking experiments with San Miguel bitumen presented in Example I
and on experience
with conversion processes in commercial refineries. Two viscosity-temperature
relationships from
FIG. 7 were considered in the computer simulations without fracturing: that of
Midway Sunset
heavy crude oil and that of San Miguel bitumen. Only the viscosity-temperature
of relationship of
San Miguel bitumen was considered in the simulation incorporating fracturing.
Simulation results are summarized in Table 4. The computer simulations show
that
without horizontal fracturing, in situ hydrovisbreaking could only be applied
with difficulty to
either a heavy crude oil having the viscosity characteristics of Midway Sunset
crude or to San
Miguel bitumen because the lack of fluid mobility within the formation caused
a very rapid build-
up of pressure when injection of steam and hydrogen was attempted. In general,
the cycles of
injection and production could be sustained for only a few minutes, resulting
in insignificant to
modest hydrocarbon production.
The final column of Table 4 lists results from the computer simulation of
continuous in
situ hydrovisbreaking in which the physical properties of a part of the
formation were altered to
simulate horizontal fracturing throughout the production unit. In this case,
significant quantities
of upgraded hydrocarbon are recovered, indicating that in situ
hydrovisbreaking can be
successfully conducted in a formation which has been fractured to enhance the
mobility of a very
viscous hydrocarbon. Recoveries greater by orders of magnitude can be
anticipated for a
fractured versus unfractured operation.
CA 02363909 2001-11-28
Table 4
Simulation of In Situ Hydrovisbreaking in the Absence and Presence of
Formation Fracturing
(Example IV)
No Fracturing With Fracturing
Operating Mode (Cyclic) (Continuous)
Type of Hydrocarbon Heavy Crude Bitumen Bitumen
Dynamic Viscosity @ 500 F, cp(l) 2 10 10
Days of Operation 70 35 79
Steam Injected, barrels (CWE)(z) 2,625 151 592,000
Hydrogen Injected, Mcf(3) 3,329 185 782,000
Cumulative Production, barrels 4,940 14 175,000
Hydrocarbon Recovered, % OOIP(4) 9.3 0.03 65.8
Gravity Increase, API degrees 1.2 5.8 10.0
(') From FIG. 7
(2) Cold water equivalents
(3) Thousands of standard cubic feet
(4) Original oil in place
Example V
Advantages of In Situ Hydrovisbreaking Compared to Steam Drive
Example V teaches the advantages of the upgrading and increased recovery which
occur
when a heavy hydrocarbon is produced by in situ hydrovisbreaking rather than
by steam drive.
The example also demonstrates the feasibility of applying in situ
hydrovisbreaking to recover a
very heavy hydrocarbon.
Through computer simulation, San Miguel bitumen was produced by steam drive
(FIG. 6,
"Base Case") and by in situ hydrovisbreaking (FIG. 6, "Case B") under
identical conditions. The
CA 02363909 2001-11-28
31
yield of hydrocarbons was more than 1.8 times greater from in situ
hydrovisbreaking. Moreover,
the API gravity of the hydrocarbons produced by in situ hydrovisbreaking was
increased by more
than 15 while there was no significant improvement in the gravity of the
hydrocarbons produced
by steam drive.
Table 5
ISHRE Process Compared to Steam Drive
(Example V)
Continuous Continuous
Operating Mode Steam Drive In Situ Hydrovisbreaking
Days of Operation 360 360
Injection Temperature, F
Steam 600 600
Hydrogen - 1,000
Cumulative Injection
Steam, barrels (CWE) 1,440,000 982,000
Hydrogen, Mcf 0 1,980,000
Cumulative Production
Hydrocarbon, barrels 129,000 239,000
Hydrogen, Mcf 0 1,639,000
Total Recovery
Hydrocarbon, %OOIP 48.6 89.9
Hydrogen, % injected - 82.8
In Situ U radin DAPI degrees 0 15.3
CA 02363909 2001-11-28
31
~,.
References
1. "Analysis of Heavy Oils: Method Development and Application to Cerro Negro
Heavy
Petroleum," Bartlesville Project Office, U.S. Department of Energy, December
1989.
2. Britton, M.W. et al.: "The Street Ranch Pilot Test of Fracture-Assisted
Steanlflood
Technology," Journal of Petroleum Technology, March 1983.
3. Graue, D.J. and K. Karaoguz: "Conceptual Simulation of the In Situ
Hydrovisbreaking
Process in the San Miguel-4 Sand, Texas, for World Energy Systems," NITEC,
LLC,
October 1996.
4. Hertzberg, R.H. and F. Hojabri: "The ENPEX Project - System Design and
Economic
Analysis of an Integrated Tar Sands Production and Upgrading Project."
5. Meyer, R.F. and C.J. Schenk: "An Estimate of World Resources of Heavy Crude
Oil and
Natural Bitumen," Proceedings of the Third UNITAR/UNDP International
Conference of
HC&TS, Alberta Oil Sands Technology and Research Authority.
6. Stang, H.F. and Y. Soni: "Saner Ranch Pilot Test of Fracture-Assisted
Steamflood
Technology," Journal of Petroleum Technology, June 1987.
7. Stapp, Paul R.: "In Situ Hydrogenation," Bartlesville Project Office, U. S.
Department of
Energy, December 1989.
8. Ware, C.H. and R.M. Amundson: "An Advanced Thermal EOR Technology,"
Proceedings
of the 1986 Tar Sands Symposium, Laramie, Wyoming, 1986.
