Heavy oil recovery process using cyclic carbon dioxide steam stimulation

A method for the recovery of viscous oil from subterranean formations including tar sands by the injection of a mixture of carbon dioxide and steam into the formation through an injection well, after which formation fluids are recovered from the well in a cyclic manner, using the well alternately for injection and production. Incremental recovery is optimized by maintaining the ratio of carbon dioxide to steam within the range 200 to 300, preferably 230 to 270 SCF carbon dioxide per barrel of steam (with water equivalent) in the injected mixture.

FIELD OF THE INVENTION 
This invention relates to a method for the recovery of oil from oil-bearing 
formations containing viscous oils or bitumen. More particularly, the 
invention relates to a method for the recovery of oil from a subterranean, 
viscous oil-containing formation penetrated by at least one well by 
injecting a mixture of carbon dioxide and steam. 
BACKGROUND OF THE INVENTION 
The recovery of low API gravity or viscous oil from subterranean 
oil-bearing formations and bitumen from tar sands has generally been 
difficult. Although some improvement has been realized in the recovery of 
heavy oils, i.e., oils having an API gravity in the range of 10.degree. to 
25.degree. API, little success has been realized in recovering bitumen 
from tar sands. Bitumen can be regarded as a highly viscous oil having an 
API gravity in the range of about 5.degree. to about 10 .degree. API and a 
viscosity in the range of several million centipoise at formation 
temperature. Bitumens of this kind may be found in essentially 
unconsolidated sands, generally referred to as tar sands, of which there 
are extensive deposits in the Athabasca region of Alberta, Canada. While 
these deposits are estimated to contain about several hundred billion 
barrels of bitumen, recovery from them, as indicated above, using 
conventional techniques has not been altogether successful. The reasons 
for the varying degrees of success arise principally to the fact that the 
bitumen is extremely viscous at the temperature of the formation, with 
consequent very low mobility. In addition, the tar sand formations have 
very low permeability, despite the fact they are unconsolidated. 
Because the viscosity of viscous oils decreases markedly with increases in 
temperature, thermal recovery techniques have been investigated for 
recovery of bitumen from tar sands. These thermal recovery methods 
generally include steam injection, hot water injection and in-situ 
combustion. 
Typically, such thermal techniques employ an injection well and a 
production well transversing the oil-bearing or tar sand formation. In a 
conventional throughput steam operation, steam is introduced into the 
formation through an injection well. Upon entering the formation, the heat 
transferred to the formation by the hot aqueous fluid lowers the viscosity 
of the formation oil, thereby improving its mobility. In addition, the 
continued injection of the hot aqueous fluid provides a drive to displace 
the oil toward the production well from which it is produced. 
Thermal techniques employing steam also utilize a single well technique, 
known as the "huff and puff" method, such as described in U.S. Pat. No. 
3,259,186. l In this method, steam is injected via a well in quantities 
sufficient to heat the subterranean hydrocarbon-bearing formation in the 
vicinity of the well. The well is then shut-in for a soaking period, after 
which it is placed on production. After projection has declined, the "huff 
and puff" method may again be employed on the same well to again stimulate 
production. 
The application of single well schemes employing steam injection and as 
applied to heavy oils or bitumen is described in U.S. Pat. No. 2,881,838, 
which utilizes gravity drainage. An improvement of this method is 
described in a later patent, U.S. Pat. No. 3,155,160, which steam is 
injected and appropriately timed pressuring and depressuring steps are 
employed. Where applicable to a field pattern, the "huff and puff" 
technique may be phased so that numerous wells are on an injection cycle 
while others are on a production cycle; the cycles may then be reversed. 
U.S. Pat. No. 4,257,650 describes a method for recovering high viscosity 
oils from subsurface formations using steams and an inert gas to 
pressurize and heat the formation and the oil which it contains. The steam 
and the inert gas may be injected either simultaneously or sequentially, 
e.g. steam injection, followed by a soak period, followed by injection of 
inert gas. Inert gases referred to include helium, methane, carbon 
dioxide, flue gas, stack gas and other gases which are noncondensable in 
character and which do not interact either with the formation matrix or 
the oil or other earth materials contained in the matrix. 
Injection of CO.sub.2 with steam during cyclic steam stimulation of heavy 
oil reservoirs has received attention recently. Carbon dioxide dissolves 
in the oil easily and causes viscosity reduction, and swelling of the oil 
which in turn leads to additional oil recovery. Recent simulation studies 
by Leung, L. C., "Numerical Evaluation of the Effect of Simultaneous Steam 
and CO.sub.2 Injection on the Recovery of Heavy Oil", J. Pet. Tech., p. 
1591 (September 1983), and Redford, D. A., "The Use of Solvents and Gases 
with Steam in the Recovery of Bitumen from Oil Sands", J. Can. Pet. Tech., 
p. 45, (January-February 1982), confirm the benefit of CO.sub.2 -steam 
co-injection into heavy oil reservoirs. The Leung article discloses six 
cycles of steam stimulation, each with a 40,000 barrel steam (cold water 
equivalent) slug of steam injected in 40 days, as the base case. Three 
separate carbon dioxide runs with 200, 400, and 600 SCF carbon dioxide/bbl 
of steam were used for comparison. A 36% improvement in recovery was 
observed for the 400 SCF/bbl case, where majority of the incremental oil 
was obtained in the first three cycles of stimulation. After one cycle, 
Leung's results show that the optimum carbon dioxide slug size was 400 SCF 
of carbon dioxide per barrel of steam (cold water equivalent). 
In the Redford article cited above, the effect of injecting different 
solvents and gases including carbon dioxide on recovery of Athabasca 
bitumen from an oil sand pack penetrated by one injection well and one 
production well was investigated. The results showed that CO.sub.2 an 
ethane gas gave improvements in recovery over the other additives, and 
that the majority of the improvement occurred in the pressure drawdown 
phases of the experiment. Larger swept volumes resulted from addition of 
ethane and CO.sub.2 and substantially cooler fluids (non-thermally driven) 
were produced. An optimum CO.sub.2 -steam ratio was noted to exist at 
about 35-dm.sup.3 CO.sub.2 /kg steam or 197 SCF/bbl, assuming standard 
conditions. Undesirable effects of using too much gas were thought to be 
caused by reduced injectivity, reduced permeability to liquids and an 
increased tendency towards channeling of steam. 
The present invention discloses an improvement in the CO.sub.2 -steam 
cyclic process in which recovery is maximized by injection of a mixture of 
carbon dioxide and steam. 
SUMMARY OF THE INVENTION 
The present invention relates to a method of recovery oil from a 
subterranean, viscous oil-containing formation penetrated by at least one 
well in fluid communication with a substantial portion of the formation, 
comprising injecting a mixture of cabon dioxide and steam and thereafter 
recovering fluids including oil from the formation through the well. The 
ratio of injected carbon dioxide to steam is maintained in the range of 
200 to 300 SCF carbon dioxide per barrel of steam (cold water equivalent), 
preferably about 230 to 270 SCF per barrel.

DETAILED DESCRIPTION 
In its broadest aspect, this invention relates to a CO.sub.2 -steam 
push-pull or "huff and puff" stimulation method for the recovery of 
viscous oil from a subterranean viscous oil-containing formation utilizing 
a specific ratio of cabon dioxide to steam to obtain maximum oil recovery. 
A relatively thick, subterranean viscous oil-contaning formation such as a 
heavy oil or tar sand formation is penetrated by a single well in fluid 
communication with a substantial portion of the formation by means of 
perforations. A predetermined amount of a mixture of carbon dioxide and 
steam maintained at a ratio of carbon dioxide to steam of about 200 to 
300, preferably 230 to 270 SCF carbon dioxide per barrel of steam (cold 
water equivalent) is injected into the formation via the well. The 
preferred amount of carbon dioxide relative to the steam is about 250 
carbon dioxide per barrel of steam (CWE). It is preferred that the 
commingled steam be saturated steam having a quality in the range of 50% 
to about 85% and a temperature within the range of 400.degree. to 
650.degree. F. The amount of steam injected with the carbon dioxide is 
preferably about 180 barrels (cold water equivalent) per foot of net pay 
and the injection rate is preferably 6 barrels (cold water equivalent) per 
day per foot of net pay. 
After a predetermined amount of the carbon dioxide-steam mixture has been 
injected into the formation, injection of the carbon dioxide steam mixture 
is terminated, the well is opened and fluids including oil are allowed to 
flow from the formation into the well from which they are recovered. 
Production of fluids including oil is continued until the amount of oil 
recovered is unfavorable. The cycle of injection of CO.sub.2 -steam and 
production may be repeated as many times as is practical and economical. 
After injection of the CO.sub.2 -steam mixture, the well may be shut-in 
for a soak-period prior to production to allow the steam and carbon 
dioxide to "soak" or remain in the formation in order to obtain maximum 
transfer of thermal energy and viscosity reduction from the injected 
fluids to the viscous oil and the formation matrix. The length of the soak 
period will vary depending upon characteristics of the formation and the 
amount of CO.sub.2 -steam injected. 
EXPERIMENTAL 
Utilizing computer simulations, a well was sunk into a reservoir 20 feet 
thick, containing a heavy crude of 10.9.degree. API and 61900 cp at 
55.degree. F. A straight steam run was first made for comparison with 
subsequent runs utilizing various mixtures of carbon dioxide and steam. 
Saturated steam having a 70% quality and a temperature of 590.degree. F. 
was injected into the reservoir at an injection rate of 118 barrels of 
steam (cold water equivalent) per day for 30 days (total of 3540 barrels 
of steam injected), after which the well was turned around and produced 
for 120 days. Thereafter, runs utilizing mixtures of carbon dioxide and 
steam at ratios varying from 100 to 800 SCF of cabon dioxide per barrel of 
steam (cold water equivalent) were made and the amount of oil recovered 
was compared with the amount of oil recovered using steam only. In each 
case, the amount of steam injected (3540 barrels) and the injection and 
production times (30 days, 120 days) were maintained constant. 
The results from these runs are shown in the accompanying drawing in which 
the incremental oil recovered, i.e. the difference between recovery of oil 
using straight steam and recovery of oil using a specific ratio of carbon 
dioxide to steam, is plotted against the carbon dioxide/steam ratio (SCF 
per barrel). It can be seen that the incremental recovery increases 
approximately linearly up to a ratio of about 250 SCF cabon dioxide per 
barrel of steam, after which incremental recovery was approximately 
constant. The results therefore show that optimum oil recovery is realized 
when the carbon dioxide to steam ratio is about 250 SCF carbon dioxide per 
barrel of steam (cold water equivalent). Additional amounts of carbon 
dioxide do not significantly enhance oil recovery, thereby only resulting 
in additional costs of carbon dioxide.