Method of decreasing gas/oil ratio during cyclic huff-n-puff practice

A method of recovering hydrocarbons from an underground reservoir with a cyclic injection/production process, wherein after one or more injection and production cycles, a second recovery fluid is injected into the formation comprising a cosolvent, a solute, preferably polydimethylsiloxane, and the primary recovery fluid such as carbon dioxide, said second fluid composition designed for solute to drop out of solution in the formation during the later soaking and production phases.

BACKGROUND OF THE INVENTION 
This invention relates to the recovery of hydrocarbons from an underground 
reservoir by cyclic injection and production processes, wherein formation 
permeability and the gas/oil ratio is lowered, and oil recovery increased 
with the use of one or more additives in the recovery fluid. 
Numerous methods of enhanced oil recovery exist which involve the injection 
of a gaseous or a gaseous/liquid fluid into an underground formation. 
Recovery is often best where the fluid is injected at conditions so as to 
make the fluid miscible or conditionally miscible with the underground 
hydrocarbons. For non-thermal systems, the chief recovery fluid has been 
carbon dioxide. 
Gaseous or gaseous/liquid recovery fluid methods may be divided into two 
types: drive processes and cyclic processes, which are also known as 
huff-n-puff or push/pull. In drive oil recovery processes, injection and 
production of fluids occur at different wells. In cyclic oil recovery 
processes, injection and production of fluids occur through the same well. 
Besides those structural differences, drive and cyclic processes are 
substantially different in that slugs of recovery fluid are designed 
differently, times of recovery are different, well patterns are different, 
costs are different, fluid velocities are different, and so forth. 
Unlike drive recovery methods, cyclic processes are better suited for small 
oil reservoirs, particularly with the use of existing wells. The cost of 
recovery with a drive process in some smaller reservoirs, especially in 
deeper zones, may be so high as to make the reservoirs border-line 
candidates at best for oil recovery after primary or secondary recovery. 
One of the earliest disclosures of a cyclic oil recovery process was in 
U.S. Pat. No. 3,480,081, wherein the flooding medium was water, brine or 
steam. The success of steam cyclic recovery processes inevitably lead to 
the cyclic injection and production of carbon dioxide with a soaking. U.S. 
Pat. No. 4,390,068 discloses such a carbon dioxide cyclic process. Cyclic 
carbon dioxide recovery has now become a commonplace event in the oil 
field. 
Attempts to recovery heavy oils and hydrocarbons from tar sands have lead 
to a number of processes involving the injection of various solvents and 
hot fluids in "pressurization and drawdown" methods. These are similar to 
cyclic carbon dioxide methods in that various solvents and fluids are 
injected into the formation through a well to increase formation pressure. 
The fluids may or may not be allowed to soak in the formation prior to 
producing the injected fluids along with hydrocarbons through the same 
well. U.S. Pat. No. 4,324,291 is one example of these processes. 
U.S. Pat. No. 4,913,235 teaches a method for increasing the viscosity of an 
injected solvent by the addition of a polydimethylsiloxane type polymer 
and a cosolvent such as toluene. The drive process disclosed therein is 
somewhat effective in countering horizontal conformance problems resulting 
from viscosity differences between injected solvent and reservoir fluids, 
but is relatively ineffective in minimizing preferential movement of 
injected solvent through high permeability regions. 
A variation of the above method is disclosed in U.S. Pat. No. 5,095,984, 
wherein the enhanced oil recovery drive process is designed so that the 
viscosifying surfactant or polymer, such as polydimethylsiloxane, is 
soluble in the drive solvent under the injection conditions of temperature 
and pressure, but is substantially insoluble under the formation 
conditions of temperature and pressure. U.S. Pat. No. 5,095,984 discloses 
that polydimethylsiloxane or other solute can be precipitated in a drive 
process by (1) a temperature increase to reservoir temperature, or (2) 
dilution or separation of the cosolvent, but has no satisfactory solution 
for precipitation by varying pressure. The possibility of cyclic injection 
and production obviously never occurred to the author of this reference, 
for after he states that the lowering of pressure may achieve some 
precipitation, he concludes, "Unfortunately, any substantial pressure 
reduction in an underground formation is not a simple or quick task." He 
suggests the possibility of a sudden pressure pulse to drop solute in the 
desired location. See Col. 8:56-66. 
SUMMARY OF THE INVENTION 
The invention is a method of recovering hydrocarbons from an underground 
reservoir with a cyclic injection/production process, which comprises 
performing a cyclic recovery method with a few twists. Initially, a first 
recovery fluid is injected into the formation through a well, said 
recovery fluid selected from the group consisting carbon dioxide, 
nitrogen, sulfur dioxide, methane, ethane, propane, butane, pentane, and 
mixtures thereof. Injection is then ceased and the first fluid is allowed 
to soak in the formation for a period of about 1 to about 30 days. 
Hydrocarbons and other fluids are then produced through the same well. 
After one or more injection and production cycles, a second recovery fluid 
is injected into the formation through the same well, said second fluid 
comprising a cosolvent, a solute, preferably polydimethylsiloxane, and a 
fluid selected from the group of first recovery fluids, said second fluid 
composition designed for solute to drop out of solution in the formation. 
It is not necessary that the second recovery fluid have a composition 
equivalent to the first recovery fluid plus the cosolvent and solute. 
Injection of the second recovery fluid is ceased and the second fluid is 
allowed to soak in the formation for a period of about 1 to about 30 days. 
Finally, hydrocarbons and other fluids are produced through the well, 
leaving solute in the formation to reduce permeability.

DETAILED DESCRIPTION 
In cyclic injection recovery, the low density and viscosity of the injected 
recovery fluid relative to the in-place fluids frequently leads to gas 
fingering and override, causing the injected recovery fluid to bypass 
large volumes of oil. Although this may be desirable in the injection 
phase, it is disadvantageous in the production phase, resulting in the 
production of excess gas and insufficient oil. These problems are greatly 
magnified by the presence of reservoir heterogeneity in the form of high 
permeability thief zones that offer a path of least resistance and 
facilitate premature gas breakthrough during the production phase of a 
cyclic process. Once gas breakthrough occurs during production, the 
gas/oil ratio skyrockets and oil recovery declines dramatically. The 
reservoir energy invested in the injection or huff cycle is no longer 
sitting behind the oil in the late part of the production or puff cycle, 
pushing oil towards the producer. 
In cyclic processes other than steam, the recovery fluid of choice is 
carbon dioxide. Other recovery fluids that may be employed are nitrogen, 
sulfur dioxide, and low molecular weight hydrocarbons such as methane, 
ethane, propane, butane, pentane, LPG, and mixtures thereof. The recovery 
fluid may be injected at conditions at which it is miscible or 
conditionally miscible with the underground hydrocarbons, but this is not 
necessary. Although carbon dioxide is frequently mentioned herein as the 
recovery fluid, it should be understood that other recovery fluids may be 
employed in the invention method in steps instead of carbon dioxide. In 
most cases, carbon dioxide will be the predominant constituent of the 
first and second recovery fluids. 
The invention is a method of substantially reducing gas/oil ratios during 
the production phase of a cyclic process by delivering a plugging or 
permeability decreasing solute such as polydimethylsiloxane to higher 
permeability zones of the reservoir near the injection/production well 
during the second or subsequent injection/production cycles of the cyclic 
process. The reduction of these higher permeability zones during the 
production or puff phase means that the injection recovery fluid will push 
more hydrocarbons towards the production well for recovery. 
The invention method requires the injection of a first recovery fluid into 
the formation through a well, said recovery fluid selected from the group 
consisting of carbon dioxide, nitrogen, sulfur dioxide, methane, ethane, 
propane, butane, pentane, and mixtures thereof. In most cases, the fluid 
will be predominantly carbon dioxide. Injection of the first fluid is then 
terminated and the first fluid is allowed to soak in the formation for a 
period of about 1 to about 30 days, preferably about 2 to about 10 days. 
The first huff-n-puff cycle is then finished by producing hydrocarbons and 
other fluids through the well. 
After one or more initial cycles, a second recovery fluid is injected into 
the formation through the well, said second fluid comprising a cosolvent, 
a solute, and a fluid selected from the group of first recovery fluids. 
The second fluid composition is designed for solute, preferably 
polydimethylsiloxane, to drop out of solution in the formation. Injection 
of the second fluid is terminated, and the second fluid is allowed to soak 
in the formation for a period of about 1 to about 30 days, preferably 
about 2 to about 10 days. Hydrocarbons and other fluids are then produced 
through the well, leaving sufficient solute in the formation to reduce 
permeability. 
The injection, soaking and production of the first fluid may be repeated 
prior to the injection of the second fluid. The injection, soaking and 
production of the second fluid may also be repeated as desired. 
Although the recovery fluids contemplated herein may be injected in a 
liquid state (as is frequently the case with carbon dioxide), at usual 
reservoir conditions, the recovery fluids will be above their critical 
temperature, and their physical properties will vary with pressure. At 
greater pressures, the recovery fluids will behave more like liquids. The 
solubility properties of carbon dioxide and the other recovery fluids will 
decrease with decreasing pressure, and decrease with increasing 
temperature. Thus, if the recovery fluid is saturated with solute such as 
polydimethylsiloxane, the solute will tend to precipitate out as pressure 
decreases during cyclic production or temperature increases as the 
recovery fluid system warms and approaches formation temperature. 
Consequently, the solute may be precipitated from the second recovery 
fluid during the soak period by increasing temperature and during the 
production period by the decreasing pressure left in the region affected 
by the cyclic process. 
The solubility of the injected recovery fluid may be enhanced by the use of 
a cosolvent. A cosolvent is defined as any material intentionally added to 
the primary recovery fluid prior to injection that enhances the 
dissolution of the solute into the recovery fluid. The cosolvent may be a 
hydrocarbon having from about 1 to about 20 carbon atoms, toluene xylene, 
benzene, ethylbenzene and alcohol, a ketone, or a mixture thereof. 
Since the recovery fluids described herein are always injected into the 
formation at a temperature substantially lower than formation temperature, 
the recovery fluid will have a greater ability to solvate the solute prior 
to injection. After injection, the solute will tend to precipitate out of 
the recovery fluid as the recovery fluid warms to formation temperature. 
Additionally, by adjusting the concentration of the cosolvent, the 
recovery fluid can be designed to precipitate the solute out at any 
desired temperature at or below reservoir temperature. Furthermore, the 
recovery fluid, cosolvent and solute system may also be designed so that 
insubstantial precipitation occurs prior to the production or puff phase, 
with most precipitation occurring as fluids race towards the well during 
production as pressure substantially decreases. 
Unlike the drive process of U.S. Pat. No. 5,095,984, precipitation of 
solute during the substantial pressure reduction of cyclic production is 
more likely to place the permeability decreasing solute in the high 
permeability streaks or zones where it is most needed. The gas rushing to 
escape the formation during cyclic production will pass through the high 
permeability streaks. Furthermore, the high permeability streaks are the 
location where the pressure drops in the formation will be the greatest, 
encouraging more solute to drop out at those locations. 
Polydimethylsiloxane polymer available from the different sources, 
including General Electric Company, is an excellent solute for use in the 
invention. U.S. Pat. No. 5,095,984, the disclosure which is incorporated 
herein by reference, discloses solubility characteristics of 
polydimethylsiloxane as a function of temperature, pressure, and cosolvent 
concentration. In particular, it is noted that in a carbon dioxide and 
toluene cosolvent system with 6 wt % concentration of a 600,000 
centistokes polydimethylsiloxane polymer, 3050 psia is required to 
maintain the 6 wt % polydimethylsiloxane polymer in solution for 9.6 vol % 
toluene and 3500 psia is required for a 7.1 vol % toluene case. Thus, when 
pressure for the 7.1 vol % toluene case falls below 3500 psia the system 
will no longer be able to maintain 6% polydimethylsiloxane in solution. 
The polymer will start dropping out. Similarly, if the cosolvent was 
diluted or separated from the recovery fluid such that the concentration 
of cosolvent decreased, polydimethylsiloxane, or other similar polymers 
would start dropping out of solution at the same reservoir pressure and 
temperature. At lower reservoir pressures and higher temperatures, greater 
quantities of solute would drop out of solution. 
Additionally, for the 9.6 vol % toluene cosolvent case, 6 wt % 
polydimethylsiloxane will remain in solution at 100.degree. F. and 3050 
psia. But when temperature increases to 130.degree. F., 3500 psia pressure 
is required to maintain solubility of the same 6% of solute. Thus, an 
increase in temperature from 100.degree. to 130.degree. F. at the same 
pressure would cause solute to drop out of solution. Moreover, in the 
invention disclosed herein wherein substantial temperature increases and 
substantial pressure decreases would occur during the soaking and 
production phases of the cyclic process, substantial quantities of solute 
(polydimethylsiloxane) would drop out of solution. 
An additional difference over drive processes lies in the fact that is 
preferred to conduct the injection phase of a cyclic process at an 
injection rate high enough to drive the recovery fluid through the 
formation at a velocity greater than critical velocity. Since velocity 
greater than critical velocity promotes fingering and conformance 
problems, velocities greater than critical velocity are highly undesirable 
in hydrocarbon drive processes. For a discussion of critical velocity, 
please see U.S. Pat. Nos. 3,811,503; 3,878,892; 4,136,738; 4,299,286; 
4,418,753; and 4,434,852, the disclosures of which are incorporated herein 
by reference. 
However, in cyclic processes it is frequently desirable to promote 
fingering during the injection phase, as the reservoir volume invaded by 
the carbon dioxide is increased, allowing more residual oil to be 
contacted by the carbon dioxide. In general, experience has shown us that 
the volume actually invaded by carbon dioxide at high injection rates will 
be about 3 to about 5 times the actual reservoir volume of carbon dioxide 
injected. Thus, about 5% to about 15% of injected pore volume at 
sufficiently high injection rates can invade about 15% to as much as 75% 
of the reservoir volume. 
After a soaking time period of about 1 to about 30 days, preferably about 2 
to about 10 days, the shut-in well is reopened for production. It is 
preferred to control production so that the production well not 
immediately blow down and encourage fingering of the injected recovery 
fluid through the formation back to the well. It is desired to control the 
production phase so that velocity of the recovery fluid through the 
formation is lower during production than during injection. 
If desired, multiple push/pull (huff-n-puff) cycles can be applied to the 
well with various slug sizes until economic limits are reached. In carbon 
dioxide cyclic practice, up to six or seven cycles have been performed on 
a single well. Of course, more could be performed if sufficient recovery 
was achieved in later cycles to justify further injection and production 
costs. The invention method should reduce the number of cycles needed per 
well. 
Depending upon the number of wells in a field subjected to the invention 
method, economic limits can be extended by recycling the produced recovery 
fluid for further injection. This would involve separating the recovery 
fluid such as carbon dioxide from the produced fluids and reinjecting the 
separated recovery fluid with or without some produced hydrocarbons. Some 
quantities of produced hydrocarbons may enhance the ability of the 
recovery fluid such as carbon dioxide to recover additional hydrocarbons 
in future cycles. However, recycling produced hydrocarbons with the 
primary recovery fluid will affect the solubility of any solute such as 
polydimethylsiloxane added to the recovery fluid. 
Many other variations and modifications may be made in the concepts 
described above by those skilled in the art without departing from the 
concepts of the present invention. Accordingly, it should be clearly 
understood that the concepts disclosed in the description are illustrative 
only and are not intended as limitations on the scope of the invention.