The present invention relates to a method of enhancing oil recovery(EOR) in layered oil reservoirs.

Fluid flow in porous media is governed by the interaction of viscous, gravity and capillary forces. It is well recognized that cross-flow has significant impact on sweep efficiency of immiscible displacement in layered reservoirs. Both gravity and viscous forces have been extensively studied in the literature. However, the impact of capillary forces is generally under-estimated in field simulation studies especially for carbonate reservoirs.

In reservoirs where the high-permeability zone is at the top of low permeability zone, under water flooding the injected water tends to flow through the upper zone along the high permeability layers and no or very slow cross flow of water into the lower zone occurs, resulting in very poor sweep of the lower zone. The main difficulty with achieving high recovery factors for the low permeable lower zone is the limited vertical drainage of injection water that in the first instance enters the high permeable upper zones. If fluid flow would be controlled by viscous and gravity forces alone, a much more efficient recovery of the oil in the lower zone would take place than is apparently occurring as gravity leads to cross flow of injected water from the top to the bottom zone of the reservoir. Moreover, in water-wet reservoirs, capillary forces align with gravity (i.e. act in the same direction, helping to flood the Lower reservoir) and result in very good sweep efficiency of the low permeability lower zone. However, for non-water-wet layered reservoirs capillary forces will act opposite to gravity and that results in a barrier which retards water from moving downwards, limits cross-flow between the different zones and leads to poor sweep efficiency of the lower zone.

A variety of enhanced oil recovery techniques have been employed in order to increase the recovery of oil from oil reservoirs. These techniques include thermal recovery methods, chemical methods and miscible flooding.

Fluid drive displacement of oil from an oil-containing formation utilizing CO₂ is known to enhance the recovery of oil by vaporizing/condensing drive, which results in reducing residual oil saturation. However, for reservoirs of high permeability contrast especially when the high permeable layers are in the upper part of the reservoir, a conventional CO₂ (immiscible or miscible) flood becomes less effective because of gravity override and/or viscous fingering due to unfavourable mobility ratio. Therefore, gas based EOR methods (including CO₂ and other miscible gases) will suffer from the same problem encountered during water flooding as injected gas will migrate rapidly to the high permeable layers (even faster than water) in the upper zone and results in poor sweep (worse than water flooding case) of the low permeable lower zone of the reservoir.

It is known that the oil displacing efficiency of a CO₂ drive can be improved by mixing the CO₂ with a foaming agent to produce a CO₂ foam oil recovery driving fluid. The foam is effective at controlling CO₂ (or other gases) channelling due to stratification and fingering. In addition, the foam also effectively reduces the mobility of CO₂ (or other gases) in porous media and controls CO₂ (gas) injection profiles, resulting in increased oil recovery and sweep improvements.

Numerous patents have been issued on the recovery of oil using a CO₂ foam drive, which include U.S. Pat. Nos. 3,330,346; 4,113,011; 4,380,266, 4,860,828 and 5,502,538. In addition, U.S. Pat. No. 4,577,688 discloses the use of steam, CO₂ and a foaming agent in an enhanced oil recovery process.

It is an object of the present invention to enhance oil recovery in oil reservoirs of different levels of heterogeneity, both lateral and vertical heterogeneity, and different wettability characteristics (mixed-wet to oil-wet).

In accordance with the invention there is provided a method of enhancing the oil recovery from a layered oil reservoir with an upper layer that is more permeable than a lower layer of the reservoir, which method comprises:

1. a) injecting an aqueous liquid through an injection well into the upper layer;
2. b) injecting a non-aqueous fluid into the lower layer; and
3. c) recovering oil from the layered oil reservoir through a production well; and wherein:
   • the aqueous liquid and/or the non-aqueous fluid carries a foaming agent; and
   • at least one of the injection and production wells comprises a permeable fluid transfer section with a substantially horizontal orientation.

Optionally the foaming agent mixed with an aqueous liquid is injected into the upper layer and simultaneously a non-aqueous fluid is injected into the lower layer.

Optionally the non-aqueous fluid is injected intermittently in slugs, which are alternated by injection of slugs of water, known as water alternating gas (WAG) cycling, into the lower layer and simultaneously a foam agent mixed with the aqueous liquid is injected into the upper layer.

The method may further comprise contacting the hydrocarbons in the reservoir with the foam so as to assist in the recovery of hydrocarbons from the reservoir.

As the gas migrates to the high permeability upper layers, foam may be formed in-situ, which results in reducing the gas mobility in the upper high permeable layer. In combination with the high-pressure gradient in the upper zone due to water injection, the formation of foam will confine the gas in the lower zone and improves the sweep efficiency and recovery of oil.

Optionally, the aqueous liquid is injected in the upper zone through a first injection well and non-aqueous fluid is injected through a second injection well with a substantially horizontal permeable fluid transfer section through which the non-aqueous fluid is injected into the lower layer. The first and second injection wells may be formed by substantially horizontal branches of a branched multilateral injection well.

The production well may also have a substantially horizontal fluid transfer section, which is oriented substantially parallel to the substantially horizontal fluid transfer section of the second injection well.

The present invention more effectively utilizes the CO₂ (or other gases) foam in a CO₂ (or other gases) foam enhanced oil recovery process from a hydrocarbon bearing formation penetrated by at least one injection well and at least one spaced-apart production well wherein the gas is only injected in the low permeable lower zone and simultaneously injecting aqueous liquid in the high permeable upper zone of oil reservoir. The foaming agent is either injected together with the non-aqueous fluid into the lower layer or together with the aqueous liquid into the upper layer.

The invention is particularly suited for layered oil reservoirs having a zone that is more permeable than the other zones and where there is an impediment for water to flow from the upper to the lower reservoir section due to e.g. (vertical) permeability reduction at the interface or a capillary pressure barrier. It is also applicable for improving oil recovery from the low permeable layers inter-bedded within the more permeable reservoir unit.

The current invention aims to provide a method that is stable and robust to reservoir lateral and vertical heterogeneity using both vertical and horizontal well technology. As the main reason for the low recovery factor of oil and the poor sweep efficiency of the lower zone is the lack of cross flow of water from the upper zone to the lower zone by either vertical permeability reduction at the interface and/or capillary pressure barrier, improved recovery can be achieved by either enhancing cross flow from the upper zone into the lower zone or reducing cross flow from the lower zone into the upper zone. Enhancing cross-flow of the aqueous phase from the upper to the lower zone can be achieved by reducing the mobility of the aqueous phase in the upper zone forcing it to cross-flow into the lower zone. Reducing the mobility of the aqueous phase in the upper zone is achieved by, for example, polymer solution, polymer-surfactant solution or alkaline-polymer surfactant, which is a subject of European patent application 09154794.3.

In accordance with the present invention, the mobility of the aqueous phase is reduced by trapping gas or foam hence forcing it to cross-flow into the lower zone and to the low permeable layers within the upper zone. Therefore, oil recovery and sweep efficiency of oil in the lower zone is improved by the combination of water cross-flow from the upper to the lower zone and confining the injected gas into the lower zone due to reducing gas mobility in the upper zone. Limited or no foam is generated in the lower zone, hence the mobility of fluids in this zone is not affected.

In practicing the invention, a variety of injection schemes can be used:

• 1- Simultaneously injecting an aqueous liquid in the upper high permeable zone and a mixture of gas and foaming agent in the lower low permeable zone.
• 2- Simultaneously injecting an aqueous liquid and foaming agent in the upper high permeable upper zone and gas (preferable miscible with the reservoir oil) in the low permeable lower zone.
• 3- Simultaneously injecting an aqueous liquid and foaming agent in the upper high permeable upper zone and WAG (water alternating gas) in the low permeable lower zone.
• 4- The mixture of aqueous liquid and foaming agent is injected intermittently in slugs, which are alternated by injection of slugs of aqueous liquid alone into the high permeable upper zone and injecting non-aqueous fluid into the lower low permeable zone.

In the four injection schemes described above, as the gas migrates to the high permeable upper zone, foam is generated in-situ only in the high permeable upper zone and leads to reducing the mobility of fluids in this zone. Oil recovery from the lower zone is improved by a combination of two effects:

• 1- The mobility of the aqueous stream in the high permeable upper zone is reduced due to the generation of foam. Gas (or foam) trapped in the upper zone will reduce water relative permeability in the upper zone and enhance cross flow of water into the lower zone.
• 2- The continuous water injection in the upper zone creates a pressure gradient which in combination with the reduced mobility of the gas due to the generation of foam will limit cross flow of gas into the upper zone and lead to the confinement of a significant portion of the gas into the lower zone.

The foam-forming composition may comprise water and an effective foam-forming amount of surfactant, which may be any surfactant type known in the art.

The method may further comprise contacting the hydrocarbons in the reservoir with the foam so as to assist in the recovery of hydrocarbons from the reservoir.

The gas which can be employed includes any of those known in the art, e.g., carbon dioxide, nitrogen, methane, flue gas and the like or mixtures of hydrocarbons such as methane with any of ethane, propane, or butane, flue gas and the like.

It is to be understood by those skilled in the art that this composition can be used either in cyclic ("huff and puff") or drive recovery methods under either miscible or immiscible conditions.

The invention will now be described by way of example in more detail with reference to the accompanying drawings, wherein:

• Figure 1 shows schematically a cross-section of the subsurface two-layer oil reservoir;
• Figure 2 shows a comparison between the method according to the present invention and a typical water flood;
• Figure 3 is a schematic three dimensional view of a layered oil reservoir which is traversed by and a production well having a substantially horizontal inflow section and two injection wells of which one has a substantially horizontal permeable lower fluid transfer section; and
• Figure 4 is a schematic three dimensional view of a layered oil reservoir which is traversed by a branched fluid injection well having two substantially horizontal fluid injection branches and a production well having a substantially horizontal inflow section.

Reference is now made to Figure 1. Figure 1 shows schematically a layered subsurface oil reservoir 1. For the sake of clarity the layers above and below the reservoir 1 are not shown. The layered oil reservoir 1 comprises an upper layer 2 and a lower layer 3. The upper layer 2 of the oil reservoir 1 is more permeable than the lower layer 3. The layered reservoir is penetrated by a first injection well 5 and a second injection well 7, and by a production well 10.

Through the first injection well 5 an aqueous liquid is injected into the upper layer 2 of the layered reservoir 1. Simultaneously a non-aqueous fluid that is injected through the second injection well 7 into the lower layer 3. Produced oil is recovered from the production well 10, which is perforated in the lower layer 3.

Instead of injecting the aqueous and gaseous streams through two wells 5 and 7 with perforated intervals in the upper and lower section of the reservoir respectively, at a close distance, the streams can be injected through two strings in one well (not shown).

In accordance with the invention, foaming agent can be mixed with either the aqueous liquid injected in the upper layer 2 or the gas injected in the lower layer 3.

In accordance with the invention, the gas can be miscible or immiscible with miscible gas performing better than immiscible gas.

In accordance with the invention, in case the foaming agent is added to the aqueous phase and injected in the upper layer 2, the injection in the lower layer can be either continuous gas or WAG.

In accordance with the invention, in case the foaming agent is carried by the gas injected in the lower layer 3, then aqueous phase (water or brine) is continuously injected in the upper layer 2.

In accordance with the invention (the case of injected aqueous liquid in the upper layer 2 and gas carrying foaming agent in the lower layer 3), the ratio of the injection rates for aqueous liquid and non-aqueous fluid is suitably so selected that the rate of advance of the aqueous liquid (arrow 11) in the upper layer 2 is larger than or equal to the rate of advance of the non-aqueous fluid (arrow 12) in the lower layer 3. In this cross flow of the injected non-aqueous fluid to the upper layer 2 is reduced. However, downstream of the fronts 13 and 14, the flow rate of the hydrocarbons (arrow 15) flowing through the more permeable upper layer 2 is much larger than the flow rate of the hydrocarbons (arrow 16) flowing through the less permeable lower layer 3.

Suitably, the gaseous fluid can include carbon dioxide, nitrogen, methane, or any other hydrocarbon combination. Moreover, the gas can be miscible or immiscible with the reservoir oil. The gas which can be employed includes any of those known in the art, e.g., carbon dioxide, nitrogen, methane, flue gas and the like or mixtures of hydrocarbons such as methane with any of ethane, propane, or butane, flue gas and the like.

The invention will now be described with reference to the below example which uses CO₂ as the non-aqueous injected fluid. However, it should be noted that the invention is not limited to this example and other gases can be used in actual field applications.

A numerical model that comprises the most salient characteristics of an actual reservoir will serve to illustrate the merits of the invention. There are two geological sections with a permeability contrast of up to 100:1, wherein the upper layer 2 has the higher permeability. About 60% of the original oil in place is in the lower layer 3. The CO₂ is continuously injected in the lower zone (supplied through the second injection well 7), aqueous liquid that carries the foaming agent is injected in the upper zone (supplied through the first injection well 5).

Reference is now made to Figure 2, which shows a comparison between the method according to the present invention and a typical water flood. On the horizontal axis is the amount of liquid injected (both aqueous and gaseous) into the upper and lower layers 2&3 in pore volumes injected. On the left vertical axis we put the cumulative amount of oil produced (as a fraction of the original oil in place) and the water-cut (as a volume fraction of water in the mixture of water and oil), and on the right vertical axis we put the gas-oil-ratio (in 1000 cubic feet at standard pressure and temperature per barrel of oil). The forecasts were generated with a three dimensional numerical model, which simulated a line drive of horizontal injector(s)/producer(Solid line 20 shows the cumulative oil production for the method according to the present invention, and dashed line 21 shows the cumulative oil production for the water flood. Solid line 24 shows the water-cut for the method according to the present invention and dashed line 25 shows the water-cut for the water flood. Solid line 28 shows the gas-oil-ratio for the method according to the present invention and dashed line 29 shows the gas-oil-ratio for the water flood.

Figure 2 illustrates how oil production from a layered oil reservoir is enhanced by the method according to the present invention.

Figure 3 is a schematic three dimensional view of a layered oil reservoir 2,3 which is traversed at one side thereof by a production well 10 having a substantially horizontal inflow section 10A, and at an opposite side by a substantially vertical first injection well 5 and a second injection well 7, where the second injection well 7 has a substantially horizontal permeable fluid transfer section 7A in the lower layer.

Figure 4 is a schematic three dimensional view of a layered oil reservoir 2,3 which is traversed by a production well 10 having a substantially horizontal inflow section 10A and a branched multilateral fluid injection well 5,7 having an upper substantially horizontal fluid injection branch 5A through which an aqueous liquid is injected into the upper layer, as illustrated by arrow H₂O, and a lower substantially horizontal fluid injection branch 7A, through which a non-aqueous fluid is injected into the lower layer 3 as illustrated by arrow CO₂.

The substantially vertical upper section (5,7) of the branched multilateral fluid injection well may comprise co-axial or parallel liquid and fluid injection conduits (not shown) through which aqueous liquid is supplied to the upper branch 5A and through which non-aqueous fluid is supplied to the lower branch 7A.