Carbon-dioxide-assisted production from extensively fractured reservoirs

In an oil reservoir which is extensively fractured, the amount of oil recovered is increased by forming gaseous and liquid layers within the fracture network, flowing gaseous CO.sub.2 into the gaseous layer, and producing liquid which contains oil from the liquid layer. The rates and locations of those injections and productions are correlated to keep the interface between the gaseous and liquid layers at selected depths.

BACKGROUND OF THE INVENTION 
The invention relates to a process for increasing the amount of oil which 
can be recovered from an extensively fractured oil reservoir. 
An extensively fractured oil reservoir is composed of relatively small, low 
permeability matrix blocks separated from each other by a network of 
interconnected fractures (which may be supplemented by solution channels, 
vugs and other cavities). In such reservoirs, some oil is often found 
within the fractures but most of the oil is present within the low 
permeability matrix blocks. Although secondary recovery processes are 
needed to increase the oil recovery, the conventional process, such as 
waterflooding, gas injection or the like, are generally inapplicable in a 
highly fractured reservoir. 
For example, a publication by S. J. Pirson, bulletin of the American 
Association of Petroleum geologist, Vol. 37, February 1953, page 232, 
discusses production problems of highly fractured reservoirs. It indicates 
that, in view of the tendency for the gravity segregation of fluids in the 
fracture network and capillary effects to trap oil within the matrix 
blocks, it is desirable to reduce the extent of gravity segregation by 
applying a high horizontal drive pressure gradient and as high a draw down 
(at the production well) as can be employed without undue water 
encroachment. Alternatively, it recommends selectively completing the 
wells for producing only from the lower zone (e.g., by plugging-off the 
upper zone) and using cyclic depressurizations followed by gradual 
depressurizations during production cycles. 
In a publication by S. H. Raza, First Turkey Petroleum Congress, Ankara, 
Turkey, Dec. 14-16, 1970 proceedings, pages 27-133, November 1971, such 
production problems are further discussed. It mentions that, in addition 
to the unsuitability of waterflooding, gas injection and the like, a 
water-imbibition procedure is only applicable where the reservoir is 
strongly water-wet and then may provide only an unattractively low rate of 
production. If the reservoir is sealed to an extent such that fluids can 
be confined at relatively high pressures, a cyclic pressure pulsing 
process can be used. 
In a cyclic pressure pulsing process one or two water pressure cycles 
precede at least one gas pressure cycle or a series of alternating gas and 
water pulsing cycles. In such processes, nitrogen, methane and carbon 
dioxide have been indicated to be equally effective where oil viscosity is 
relatively low, although the volume required for a pressurization with 
C0.sub.2 is significantly greater. However, such pressuring and 
de-pressuring steps are relatively expensive unless the total oil-free 
fluid filled pore space of the reservoir is small enough that it can be 
refilled with relatively high pressurized gas in a relatively short time. 
It is known that, when injected into a subterranean reservoir and subjected 
to sufficient pressure, carbon dioxide becomes relatively miscible with 
oil. When C0.sub.2 dissolves in an oil the oil becomes a solution having a 
larger volume, a lower viscosity, and a lower interfacial tension against 
a gas. Numerous patents have proposed using C0.sub.2 as a fluid to be 
injected to cause a miscible fluid drive that displaces oil toward a 
production location. Such processes, which require a relatively uniformly 
permeable reservoir, are described in patents such as British Patent No. 
669,216 and U.S. Pat. Nos. such as 2,623,596; 2,875,883; 2,936,030; 
3,065,790; 3,120,265; 3,405,761; 3,687,198 etc. 
U.S. Pat. No. 3,653,438 describes a gravity-aided miscible-drive process 
that is particularly applicable to a viscous oil reservoir having a high 
and relatively uniform permeability. An oil-soluble gas such as carbon 
dioxide and/or a mixture of carbon dioxide and/or a mixture of carbon 
dioxide and liquid petroleum gas is injected at an upper level within the 
reservoir while a petroleum product comprising a mixture of oil and gas is 
produced at a lower level. Where the oil zone overlies an active aquifer, 
nitrogen or any low valued gas is preferably injected into the highest 
point within the reservoir to maintain an overall reservoir pressure that 
prevents or controls the water encroachment. 
However, as indicated above, such previously proposed drive or drainage 
processes that involve the flowing of oil through a reservoir of 
relatively uniform permeability are not applicable to an extensively 
fractured reservoir. In such a fractured reservoir the permeability is 
very high in the fracture network but is very low within the 
oil-containing rock matrix. Drive fluids flow easily through the fracture 
network, but bypass the oil in the matrix blocks. In addition, because of 
the gravity segregation of the fluid within the fractures, any undissolved 
gas spreads quickly to the vicinity of any production location. Therefore, 
if a mixture of liquid and undissolved gas is produced while an 
oil-soluble gas is being injected, the injected gas may be produced before 
any significant proportion of it has been dissolved in oil. 
SUMMARY OF THE INVENTION 
The present invention relates to increasing the amount of oil recovered 
from an extensively fractured reservoir in which liquid hydrocarbons are 
contained in matrix blocks of low permeability surrounded by a relatively 
highly permeable network of interconnected fractures. The reservoir is 
first treated by injecting or producing fluid to the extent necessary to 
form, within the fracture network, a substantially gas-filled gas layer 
that overlies a substantially liquid-filled liquid layer. Fluid which 
contains or comprises gaseous CO.sub.2 is then injected so that gaseous 
CO.sub.2 flows into the gas layer in an amount sufficient to provide a 
CO.sub.2 partial pressure of at least about 30% of the total pressure in 
at least a lower portion of the gas layer. An oil-containing liquid which 
is substantially free of undissolved gas is produced from the liquid 
layer. And, the rates and locations of the injections and productions are 
correlated or adjusted to keep the interface between the gas and liquid 
layers at selected depths within the fracture network.

DESCRIPTION OF THE INVENTION 
The present invention is, at least in part, premised on the following 
discovery. When a gas layer is present within an extensively fractured 
reservoir, liquid hydrocarbons can be recovered at a suitable rate by 
maintaining an atmosphere of CO.sub.2 within the fracture network. In this 
way the tendency for fluids to flow freely and undergo gravity segregation 
within the network of fractures (which hindered production in prior 
processes) can be used as an advantage. When a fluid that contains or 
comprises gaseous CO.sub.2 is injected, the CO.sub.2 is relatively quickly 
distributed throughout the horizontal extent of the gas layer. This causes 
the CO.sub.2 gas to contact and dissolve in the oil contained in many of 
the matrix blocks. The CO.sub.2 -dissolution swells the oil, while 
reducing its interfacial tension and viscosity, and displaces the swollen 
oil into the fractures. Within the fractures the swollen oil is segregated 
into a location near the interface between the gas and liquid layers. From 
there a substantially gas-free liquid that contains the oil can readily be 
produced. 
The probable efficiency of such an oil production mechanism has been 
indicated by laboratory tests. Cores of earth formations of permeabilities 
of from about 1 to 10 millidarcies were cleaned and dried in the air and 
then were substantially saturated with a highly refined kerosene fraction 
predominating in C-11 to C-15 hydrocarbons. Models of low permeability 
matrix blocks surrounded by highly permeable fractures were formed by 
placing core samples, which were cylinders about 1/2 inch in diameter and 
21/2 inches long, in plastic centrifuge tubes. The core-containing tubes 
were maintained at 70.degree. F. and the air in the tubes was displaced 
with gaseous CO.sub.2 at about 850 psi. At such pressure and temperatures, 
if the surrounding gas is air or nitrogen, instead of CO.sub.2, the 
capillary forces which hold the oil in the pores are stronger than the 
force of gravity, and the oil does not drain. But, when the surrounding 
gas is sufficiently rich in CO.sub.2, the interfacial tension between the 
CO.sub.2 and the oil is low enough so that oil drainage occurs at a 
significant rate. Since the interfacial tension between an oil and air in 
known to be comparable to that between the oil and a hydrocarbon gas 
(e.g., a solution-gas released from an oil) such tests indicate that when 
matrix rock blocks previously exposed to hydrocarbon gas are subsequently 
surrounded by CO.sub.2 gas, a similar relatively rapid drainage will occur 
in an oil reservoir. Thus, the extent of oil recovery from an extensively 
fractured reservoir can be increased by such a process. It appears that 
this can occur even at moderate pressures (e.g., less than 1,000 psi) in 
reservoirs at moderate temperatures (e.g., less than about 100.degree. 
F.). In addition, a more substantial enhancement of oil recovery will 
occur at higher pressures (1,000 to 10,000 psi), even at higher reservoir 
temperatures (100.degree. F. to 300.degree. F.). 
In general, the present invention is applicable to substantially any 
oil-containing extensively fractured reservoir in which (a) the 
permeability within the fracture-surrounded blocks of matrix is small 
enough to trap oil by capillary action, and (b) the permeability within 
the inter-connected fractures is high enough so that fluids undergo 
gravity segregation and the pressure gradients are less than the liquid 
heads over horizontal distances of significant extent. Reservoirs to which 
the present process is applicable can be either oil-wet or water-wet or a 
combination thereof. Although such highly fractured reservoirs can be 
either predominately siliceous or carbonaceous, they are often 
carbonaceous and are commonly referred to as highly fractured limestone 
formations. Such reservoirs are encountered in the Middle East oil fields, 
and in West Texas oil fields such as the Yates Field and the TXL Devonian 
Field. Although the fractures in an extensively fractured reservoir are 
usually natural fractures, they can be natural fractures supplemented by 
artificially induced fractures or can comprise a network of relatively 
closely spaced inter-connected artificially induced fractures such as 
those resulting from a nuclear detonation, a chemical explosive and/or a 
massive hydraulic fracturing operation, etc. 
Referring to the drawing, FIG. 1 shows an extensively fractured limestone 
formation 1 located between caprock 2 and base rock 3 and penetrated by 
wells 4 and 5. As shown in FIG. 3, formation 1 contains a plurality of 
relatively impermeable matrix blocks 7 surrounded by a network of 
interconnected relatively highly permeable fractures 6. 
The wells and well-completing equipment and techniques can comprise those 
currently available. As indicated in FIGS. 1 and 2 the injection wells are 
preferably opened into fluid communication with the reservoir formation 
within an upper portion of the reservoir while the production wells are 
opened into a lower portion of the reservoir. This is preferably 
accomplished by extending each well through the reservoir and cementing-in 
a casing string which is subsequently perforated at depths at which fluids 
are to be injected or produced. However, if desired, such wells can be 
perforated throughout the reservoir interval. In this case, since the 
wells communicate with the fracture network, within it, regardless of 
where gases are injected, they are promptly segregated to the top of the 
reservoir. The bottom of a production tubing string through which liquid 
is to be produced can be isolated from the upper portion of the well 
borehole that contains it with a packer or the like. Where such a packer 
is used it is preferably one which can be relocated to change the depth 
from which fluid is produced. 
FIG. 1 illustrates the starting of the present process in a reservoir in 
which substantially all of the pore space, in both matrix blocks 7 and 
fractures 6, is filled with a mixture of aqueous liquids and hydrocarbons 
(e.g., oil). In such a situation, within the fractures, the oil would tend 
to be located above the aqueous liquid, but within the pores of the matrix 
blocks, since the tendency toward gravity segregation is opposed by 
capillary action, the extent of segregation would be much less. Both oil 
and water will often be initially distributed nearly equally over most of 
the height of a matrix rock block located above the water level existing 
in the fractures. 
In the first step of the present process, the reservoir is treated by 
injecting or producing fluid to the extent necessary to form, within the 
fracture network, a layer of gas that overlies a layer of liquid. Where 
the reservoir oil contains a significant proportion of dissolved gas and 
the reservoir fluid pressure is relatively high, such a gas layer can be 
formed by producing oil while either maintaining or reducing the reservoir 
pressure. Where the original reservoir pressure is to be maintained, gas 
can be injected through well 4 while liquid is produced through well 5, 
with substantially equal volumes of fluid being injected and produced. 
Where the reservoir pressure is to be reduced, the liquid is produced, 
with or without any gas injection, at a volumetric rate faster than that 
at which gas is injected. As shown in FIG. 2 a gas layer (or gas cap) can 
be formed, with a gas-liquid interface 8 existing between the gas and 
liquid layers within the fracture network. The depth of interface 8 is, of 
course, directly responsive to the relative rates of gas injection and 
liquid production. The depth location of the interface falls when the 
volume of liquid produced exceeds the volume of gas injected, etc. 
Whether or what kind of gas should be injected in order to form such a gas 
layer is primarily an economic decision. If a gas is injected such a gas 
can be air, nitrogen, flue gas or other low-cost gas and/or carbon 
dioxide. Where desired, such a gas can be heated and/or can comprise a hot 
vapor such as steam. If the reservoir oil contains a high proportion of 
dissolved gas for which the current market is good, if desired, the 
solution gas can be produced while another gas is injected and liquid is 
produced so that the reservoir pressure is adjusted to or is kept at a 
selected value while both oil and gas are recovered for marketing during 
the forming of a gas layer within the fracture network. If the oil is 
significantly more valuable with its gas in solution, such an oil can be 
recovered from the produced liquid while gas is being injected, with the 
relative rates being adjusted to substantially maintain or, if desirable, 
to increase the pressure within the reservoir during the forming of the 
gas layer within the fracture network. 
Where the reservoir oil viscosity is high enough and/or the oil mobility is 
low enough to impede the rate of fluid flow and/or gravity segregation of 
fluids within the fracture network, additional steps may be desirable 
prior to or during the formation of the gas cap within the fracture 
network. Conventional fluid drive and/or thermal drive procedures can be 
employed to recover the oil contained in the fractures and/or to reduce 
its viscosity or increase its mobility. In such a treatment, the drive is 
preferably conducted throughout the vertical extent of the reservoir. For 
example, this can be done by opening wells such as 4 and 5 throughout the 
total vertical interval of formation 1 and injecting a gaseous or liquid 
drive fluid through one while producing fluid through the other so that 
most of the drive flows through the fracture network while bypassing the 
matrix blocks 7. In such a fracture-cleaning step, the circulated fluid 
can comprise an aqueous liquid of the type used in a waterflood, chemical 
flood, miscible drive, or the like. Or, the fracture-cleaning fluid can 
comprise light hydrocarbon fractions (LPG), or contain or form hot fluids 
that thermally mobilize the oil. During such a fracture-cleaning step, 
particularly where a pattern of wells is employed, the pressure 
differentials due to the pressure differences between the fluid injection 
pressures and production well drawdown pressures are preferably made as 
high as feasible in order to confine the zone that is swept by the 
fracture-cleaning fluid to those within the well pattern to be employed. 
In the present process, fluid which contains or comprises gaseous CO.sub.2 
is injected so that gaseous CO.sub.2 flows into the gas layer or gas cap. 
The proportion of CO.sub.2 in at least a lower portion of the gas cap 
should be sufficient to cause a significant amount to dissolve in the 
reservoir oil. In general, in reservoirs having relatively low 
temperatures and pressures the total gas pressure should be at least about 
500 psi and the proportion of CO.sub.2 should be sufficient to provide a 
partial pressure amounting to at least about 30% of the total gas 
pressure. The CO.sub.2 -containing gas can be injected above or below the 
gas liquid interface and its injection can be continuous or intermittent. 
Because of the high permeability and tendency for gravity segregation 
within the fracture network, the CO.sub.2, or other gas injected in the 
present process, can be injected at substantially any rate not requiring 
an injection pressure that exceeds the fracturing pressure of the 
overlying formations. In an extensively fractured reservoir, any injected 
gas moves quickly into the gas cap and the pressure within the gas cap 
remains substantially the same throughout the total horizontal area 
occupied by the gas. 
In the present process fluid which contains oil and is substantially free 
of undissolved gas is produced from the liquid layer within the fracture 
network. Since the density of a reservoir oil is usually less than that of 
an aqueous liquid, the oil within such a liquid layer tends to be 
concentrated just below the gas-liquid interface. Thus, the oil-containing 
substantially gas-free liquid that is produced from the reservoir is 
preferably produced from near the top of the liquid layer. Such production 
can be intermittent or continuous. The point of the fluid withdrawal is 
preferably located such a distance below the gas-liquid interface as to 
maintain a relatively high oil-cut in the produced fluid as compared to 
water coning upward and gas coning downward into the oil layer and thus 
being produced together with crude oil. 
In the present process, the rates and locations of the injections and 
productions of fluid are correlated so that oil-containing liquid is 
produced and the gas-liquid interface remains at or is moved to selected 
depth locations within the fracture network. As known to those skilled in 
the art, in an extensively fractured reservoir, the magnitude of the oil 
saturation in the matrix blocks of the reservoir may vary with depth. If 
the reservoir has undergone a pressure decline, for example due to the 
receding of water and/or a lowering of temperature, or due to a long prior 
primary production period or the like, the gas cap may have existed for a 
significant time. In such a situation the extent to which gravity 
segregation has occurred within the matrix blocks is a function of the 
native viscosity and/or mobility of the oil, interfacial tension 
properties of the oil, the distance above or below the gas-liquid 
interface, etc. 
In general, as the gas-liquid interface is lowered in the fracture network, 
some oil and/or water will drain out of the matrix rock into the 
fractures. Gas phase either invades the matrix rock to a limited extent, 
or pervades the rock by coming out of solution in the oil if the reservoir 
pressure is reduced below the bubble point pressure during this phase of 
the process. The gas saturation (volume fraction of the pore space) in the 
matrix rock will then, because of the capillary pressure gradient due to 
interfacial tension between gas and oil, be highest at the top of the 
matrix blocks and lowest near the liquid level in the fractures. Thus, the 
oil saturation is least at the top of the blocks and is greatest at the 
oil level in the fractures. 
Where the reservoir is substantially liquid-filled at the time the process 
is started, it is generally advantageous to control the rates and 
locations of fluid injections and productions so as to move the gas 
liquid-interface from substantially the top to the bottom of the reservoir 
while maintaining enough CO.sub.2 in the gas cap to dilute and swell a 
significant proportion of the oil present in the matrix blocks. The depths 
from which the substantially gas-free liquid is produced are preferably 
adjusted to the extents required to keep them near the top of the liquid 
layer within the fracture network. The rates of fluid injections and 
productions are preferably arranged to maintain a relatively high pressure 
throughout substantially the total production operation, so that gaseous 
and liquid hydrocarbons and CO.sub.2 can be recovered during a final 
blow-down production phase involving a gradual de-pressuring of the 
reservoir. 
In the situations shown in FIGS. 4 and 5 of the drawing, a fractured 
limestone formation 11 is located between cap rock 12 and base rock 13. 
The space of formation 11 not filled with limestone is occupied by the gas 
of gas cap 14, the oil of oil zone 15, and the water of water layer 16. 
The gas cap 14 is filled with hydrocarbon gas and the pressure of the gas 
is sufficiently high to transport oil out of the fractures to the surface 
of the earth. 
Well 17 penetrates the formation 11 and communicates with formation 11 at a 
level just above the gas/oil interface 18. Well 17 is used for the 
introduction of CO.sub.2 -containing gas into formation 11. In a preferred 
embodiment the CO.sub.2 is injected just above that interface, as 
indicated by arrows 19. When that interface has been lowered, e.g., after 
the production of a certain amount of oil at a volumetric rate exceeding 
that of the gas injection, the level at which carbon dioxide gas is 
introduced into the formation 11 is lowered. This new level is shown in 
FIG. 5. As can be seen from FIG. 5, the carbon dioxide gas is introduced 
(see arrows 20) at a level just above the new oil/gas level 18. This takes 
advantage of the tendency for the oil saturation to be relatively high in 
the zone just above the gas/oil interface and the tendency for the 
CO.sub.2, which is denser than a hydrocarbon gas, to underrun the gas 
originally present and thus to be the most concentrated where the oil is 
the most concentrated. 
Well 21 also penetrates the formation 11 but communicates with it at a 
level which is relatively low in the oil zone 15 but is sufficiently far 
from above water/oil interface 22 to prevent entraining excessive 
proportions of water from the water zone 16. Well 21 thus produces a 
substantially gas-free liquid consisting mainly of oil. 
In the present process the rates and locations of the injection and 
production of fluid can be correlated so that the water/oil interface 22 
is maintained at its original location by maintaining the pressure within 
the gas cap 14 constant. This pressure may fall after opening the 
production well 21, but the introduction of carbon dioxide gas into the 
gas cap 14 via the well 17 can restore and maintain the pressure. By 
producing oil (by internal gas drive and/or by gravity drainage and/or 
under influence of the pressure in the gas cap 14) at a rate such that the 
gas/oil interface 18 will fall, the oil-filled fractures which were 
originally just below interface 18 will become filled with gas. Since the 
carbon dioxide gas supplied to the gas cap 14 (see arrow 19) has a density 
higher than that of the gas originally present in the gas cap 13, the 
fractures that fall dry will be filled with carbon dioxide gas. This gas 
will subsequently be dissolved in the oil trapped in the pore space of the 
limestone blocks surrounding the gas-filled fractures and lower the 
interfacial tension thereof to an extent such that part of this oil will 
be drained from the pore space under influence of the gravity against 
capillary forces and be collected in the oil zone 15, from where it will 
be recovered via the well 21. The injection of the carbon dioxide gas may 
also take place at other levels than the levels 19 and 20. Since the flow 
resistance through the fractures is extremely low and the density of the 
carbon dioxide gas is higher than the density of the gas originally 
present in the gas cap 14, the carbon dioxide gas may also be injected at 
a relatively high level within gas cap 14, either via the well 17 or via a 
number of other wells (not shown), since the carbon dioxide gas tends to 
flow downwards towards the gas/oil interface 18 and to follow this 
interface on its downward movement during production of oil. 
The gas cap 14 in formation 11 may result (wholly or partially) from a 
previous production of oil. In such a case, the injection well 17 
preferably communicates with the gas cap at a high level thereof to allow 
any carbon dioxide gas that is injected via this well to flow through the 
majority of fractures in the gas zone to displace hydrocarbon gas 
therefrom (via a not-shown gas production well). The carbon dioxide gas 
(which may be mixed with other gas or other gases compatible with carbon 
dioxide gas with regard to the surface tension lowerng properties thereof) 
lowers the surface tension of the oil trapped by capillary action in the 
blocks that are situated in the gas cap. Consequently, oil is drained from 
these blocks and flows through the fractures to join the oil already 
present in the fractures. 
The carbon dioxide gas used for carrying out the present method can be 
obtained from any available source. It may either be pure or mixed with 
other suitable gases. If desired, other agents for lowering the viscosity 
of oil may be added or incorporated within the injected CO.sub.2 
containing gas. For example, that gas can be heated. Such a gas may either 
be obtained from a surface source or from a subsurface source, such as a 
natural source. The carbon dioxide gas dissolved in the oil that is 
produced via the production wells can be separated therefrom, for example 
by using known separation procedures, and subsequently be reinjected into 
the fractured limestone formation. Also, at least some of the carbon 
dioxide gas which is injected can be formed by injecting an an 
oxygen-containing gas into the reservoir formation under conditions that 
allow combustion of oxygen with liquid -- and/or gaseous hydrocarbons 
(primarily within the fractures) to generate carbon dioxide gas in situ. 
Or, by conducting an underground combustion at sufficiently high 
combustion temperatures, limestone rocks in a reservoir formation can be 
decomposed, thereby generating additional quantities of carbon dioxide 
gas. 
Where the carbon dioxide gas used in the present process is mixed with 
other gases, such gases should be selected to avoid reducing the 
effectiveness of the carbon dioxide to lower the interfacial tension of 
oil. Hydrocarbons which are gaseous at the reservoir conditions, e.g., 
methane and ethane are compatible with carbon dioxide and are suitable for 
this purpose. The presence of nitrogen should, however, be minimized. In 
general, the influence of other gases on carbon dioxide in this respect 
can readily be determined in order to decide which gases that are 
available for injection purposes should be used. Also, the most favorable 
ratio of the quantities of gases injected can be easily ascertained by 
known tests. With most substantially nitrogen-free mixtures of gases 
inclusive of CO.sub.2, a mixture that contains enough CO.sub.2 to provide 
a partial pressure CO.sub.2 gas of at least about 30% of the total gas 
pressure will yield favorable results. 
Where desirable the CO.sub.2 -containing gas that is flowed into the gas 
cap may be, at least in part, derived from an injection of an aqueous 
liquid which is saturated with and/or mixed with CO.sub.2 into a lower 
portion of the reservoir, preferably near the top of the aqueous liquid 
level in a reservoir that contains an oil layer sandwiched between a gas 
cap and a water layer. Similarly, hot aqueous and/or gaseous fluids can be 
injected and circulated within either or both of the gas or liquid layers 
within the reservoir. In such procedures the average total rates and 
locations of CO.sub.2 -containing fluid injections and substantially 
liquid-fluid productions are correlated so that the interface between the 
gas and liquid layers is kept at selected depths within the fracture 
network.