Background of the Invention: As is well known, oil and other hydrocarbons are produced from a well by achieving a flow of the hydrocarbons from downhole to the surface, typically through production tubing This flow of oil occurs due to a driving force which pushes or forces the oil from downhole to the surface. In general, the oil is driven to the surface either by high pressure associated with the downhole oil reservoir (a so-called depletion drive reservoir) or by high pressure downhole water sources (a so-called water driven reservoir).

In either the depletion drive or water driven reservoirs, the recovery of produced oil decreases with time. That is, as oil is produced at the surface, the downhole pressure steadily decreases until the pressure of the downhole oil reservoir is equal to the surface pressure. Of course, at that point, the oil remaining downhole will no longer flow to the surface due to the lack of an appropriate pushing force (i. e., pressure differential).

Indeed, many oilfields leave over sixty-five (65%) percent of their oil in place in the ground due to the aforementioned lack of reservoir pressure available to remove the oil from the downhole formation. In an effort to alleviate this problem, well known enhanced recovery techniques include injecting fluids from the surface downhole (via an injection well). The injecte fluids typically comprise pressurized natural gas or treated water or steam. An example of an injection well of this type is disclosed in U. S. Patent 4,199,028 wherein enhanced recovery of hydrocarbons is accomplished through the re-introduction (i. e., injection) of natural gas containing acquifiers.

While injection wells do offer enhanced recovery of oil reservoirs, such wells suiffer from certain drawbacks and deficiencies including high cost, lack of compatibility between the driving and driven fluids, and safety concerns.

Summary of the Invention: The above-discussed and other drawbacks and deficiencies of the prior art are overcome or alleviated by the improved enhanced recovery technique of the present invention. In accordance with the present invention, energy (that is, stored pressure) from naturally occurring high pressure fluid reservoirs (typically natural gas reservoirs) located above or below the hydrocarbon reservoir to be produced are used to supply a pressure source for driving oil or other hydrocarbons to the surface. This is accomplished by accessing the high pressure reservoir and directing the accessed high pressure fluid into a downhole pressure pathway to drive the oil from the oil reservoir to the surface. In general, the present invention achieves this downhole pressure pathway by using at least two boreholes (i. e., a"production"borehole and a"self-

injecting"borehole) both of which are open to the oil reservoir and only one of which (the"self-injecting"borehole) is open to the high pressure fluid reservoir. In this way, high pressure fluid is directe from the high pressure fluid reservoir through the self injecting borehole to the oil reservoir whereupon the high pressure fluid will drive the oil from the oil reservoir into the production borehole and then to the surface.

The present invention may be utilized in a wide variety of wellbore configurations including wellbores associated with separate wells and wellbores associated with multilateral wells.

The present invention offers significant features and avantages over prior art enhanced recovery techniques. The present invention takes avantage of the energy residing in the numerus, naturally occurring high pressure reservoirs which are not typically produced due to poor economics and uses this energy to repressurize a subpressurized oil reservoir so that more oil is recovered and produced from this reservoir. In addition, the enhanced recovery technique of this invention will be of lower cost relative to conventional injection wells and will not have the safety and fluid compatibility issues associated with injection wells.

The above-discussed and other features and avantages of the present invention will be appreciated and understood by those skilled in the art from the following description and drawings.

Brief Description of the Drawings: Referring now to the drawings wherein like elements are numbered alike in the several FIGURES : FIGURE 1 is a schematic view of the enhanced hydrocarbon recovery technique of the present invention employed with two wells; FIGURE 2 is a schematic view of the enhanced hydrocarbon recovery technique of the present invention employed in a multi-lateral well; and FIGURE 3 is a graph of production rate versus time for a conventional depletion drive reservoir and a well system employing the enhanced recovery technique of the present invention.

Description of the Preferred Embodiment: Referring first to FIGURE 1, an oil and gas well field is shown for producing hydrocarbons. This field inclues a production well 10 comprise of a borehole 12 lined with casing 14. A portion of the casing 14 has been perforated in a known manner to produce perforations 16 for the purpose of producing hydrocarbons from a reservoir 18. These hydrocarbons are produced by flowing through perforation 16 and then into production tubing 20 and upward to the surface as indicated by the arrow 22.

As is well known, when reservoir 18 is initially produced, the reservoir is under significant pressure which forces or drives the hydrocarbons from the reservoir into the well and onward through the production tubing 20. However, as the hydrocarbons are produced, the pressure in the reservoir 18 steadily decreases until the pressure equalizes with the atmospheric pressure, (that is, there is no more pressure differential

or Dp) so that the hydrocarbons from reservoir 18 cease flowing into well 10 and therefore can no longer be produced.

In accordance with the present invention, underground, naturally occurring high pressure fluid reservoirs such as shown at 24 and 26 are tapped or accessed and are directe through an appropriate pathway so as to provide repressurization to oil reservoir 18 which in turn will drive additional hydrocarbons from reservoir 18 into production well 10. Typically, the naturally occurring high pressure fluid in reservoirs 24 and 26 will consist of natural gas or other trapped hydrocarbon gases. It will be appreciated however, that the high pressure fluid may also be entrapped steam or other fluids. While the pathway for directing the naturally occurring high pressure fluids to the hydrocarbon reservoir 18 may be constructed in a variety of mannes, in the FIGURE 1 embodiment, a second well 28 is formed and appropriately cased with casing 30. Casing 30 is then perforated to define perforations 32 and 34 which allow the high pressure driving fluid from reservoirs 24 and 26 to escape therefrom and enter well 28. It will be appreciated that in order for the high pressure fluids to be directe in a pathway for providing repressurization to hydrocarbon reservoir 18, well 28 must be capped (such as shown by the valve 36) to avoid any escape of the high pressure fluids to the surface. In this way, the high pressure fluid will be driven to a low pressure area which is defined by the hydrocarbon reservoir 18 (which of course will have been perforated as is shown at 3 8). The high pressure fluid (natural gas) from reservoirs 24 and 26 will apply a driving force (indicated by the gas phase 40 atop reservoir 18) and thereafter drive the hydrocarbons from reservoir 18 into production well 10. In effect, the hydrocarbon reservoir 18 will have been repressurized by

accessing the high pressure fluid (natural gas) which is naturally occurring in the ground so as to form a pressure loop between the high pressure reservoir, the hydrocarbon reservoir to be produced and the production well.

In contrast to the surface injection methods associated with prior art enhanced recovery systems, the present invention can be viewed as a self-injected system where natural gas (or other high pressure fluid) already present downhole is self-injected into an appropriate hydrocarbon reservoir so as to repressurize that hydrocarbon reservoir and enhance recovery.

The present invention may also be associated with a variety of known monitoring and control instrumentation and sensors including those monitoring and control systems disclosed in U. S. Patent No. 5,597,042, which is assigne to the assignee hereof and incorporated herein by reference. As an example, as shown in FIGURE 1, a downhole temperature sensor 42, pressure sensor 44 and flow sensor 46 is associated with the self-injecting borehole 28 to monitor parameters related to the flow of the high pressure fluid into the hydrocarbon reservoir 18. Information from sensors 42,44 and 46 can be sent to a surface or sub-surface monitoring and/or control system 48 either by a cable 50 or through an appropriate wireless communications means (such as acoustic telemetry through the casing 30). By communication of relevant parameters to the monitoring system 48, the high pressure fluid flow can be adjusted automatically or manually, as appropriate. In addition, important information relative to downhole conditions can be determined. For example, monitoring pressure/flow into the hydrocarbon reservoir versus pressure/flow out of the reservoir can determine the volume of the reservoir.

Referring now to FIGURE 2, an alternative embodiment of the present invention is shown in conjunction with a lateral or multilateral well 52. In the FIGURE 2 embodiment, well 52 inclues well casing 54 and production tubing 56 which is positioned above a production zone for producing hydrocarbons from reservoir 58.

Perforations 60 are provided to access hydrocarbons from reservoir 58 and allow for production of hydrocarbons (such as oil) through production tubing 56 and then to the surface as indicated by arrows 62. In accordance with the present invention, a lateral borehole 64 is drilled from primary borehole 52. Lateral borehole 64 will intersect both the hydrocarbon reservoir 58 and one or more naturally occurring high pressure fluid reservoirs 60. Typically, lateral 64 will be cased and appropriate perforations 66 and 68 provided so as to access high pressure fluid 60 and hydrocarbon reservoir 58, respectively. It will be appreciated that in order to establish the closed pressure loop and direct the high pressure fluid from reservoir 60 to hydrocarbon reservoir 58 along an appropriate pressure pathway defined by lateral 64, lateral 64 needs to be shut-in from primary borehole 52 (such as shown by valve 70) so that the appropriate pathway is achieved. Of course, high pressure fluid from reservoir 60 will seek the path of least resistance (that is, the lower pressure area) so that the higher pressure fluid will flow to reservoir 58 and provide a driving force to the hydrocarbons residing in reservoir 58 from reservoir 60 forcing such hydrocarbons into the producing zone of production well 58 and then into the production tubing 56 to the surface. Of course, well 52 may include any number of lateral boreholes which may intersect one or more of the same or other high pressure (natural gas) reservoirs. Well 52 may also be associated with a control and monitoring system of the type discussed with regard to FIGURE 1.

FIGURE 3 is a graph of hydrocarbon production rate versus time comparing prior art depletion drive reservoirs with a well constructed in accordance with the present invention. As shown in FIGURE 3, in a prior art depletion drive reservoir, the rate of production will increase steadily from the time the hydrocarbon is first produced until the time that the pressure in the reservoir being produced equalizes atmospheric pressure. Thus, the prior art not only leads to a situation where production totally ceases when there is an equalization in pressure, but the prior art also leads to a situation wherein the rate of production steadily decreases with time leading to inefficiencies and much higher operating costs.

In contrast, and in accordance with the present invention, by tapping or accessing a high pressure fluid reservoir such as is normally located in and around production wells, the production rate of hydrocarbons may be maintained at a steady state rate since there will be a continuous driving force against the reservoir until the naturally occurring high pressure fluid has been depleted. In a preferred embodiment, multiple high pressure gas reservoirs can be accessed in sequential time periods so that the reservoir will have a constant driving force until such time that either the hydrocarbon reservoir is depleted or there are no longer any naturally occurring high pressure fluid deposits which are accessible. Referring to FIGURE 3, it can be seen that in accordance with the present invention, not only is the production rate maintained at a steady state and high rate, but the time of producing a particular hydrocarbon reservoir is substantially decreased leading to improved efficiency and lower cost operations. More specifically, the method of this invention allows for accelerated production of the hydrocarbons in that the total hydrocarbons normally

recovered in a depletion drive well is recovered much earlier at a time T, (using the present invention) rather than a later time T2 (using conventional depletion drive techniques). In addition, the method of this invention allows for incremental (that is, increased) recovery (assuming"A"equals"B") above that of a normal depletion well of hydrocarbons"C"by supplying pressure from another zone as discussed in detail above.

The present invention is particularly important when considering the fact that many of the naturally occurring reservoirs such as shown at 24,26 and 60 in FIGURES 1 and 2 are not normally accessed or tapped since many are too small to be commercially viable and/or there are many regions in the world where natural gas (the primary constituent of the naturally high pressure reservoirs) is not an energy source which is used in that particular geographic location. The present invention thus provides maximum recovery of a particular hydrocarbon reservoir at a lower cost and over a decreased time period. This maximized recovery is accomplished without the high cost associated with injection wells as well as the compatibility issues associated with the fluids being injecte by the injection wells and the safety concerns that are associated with injection wells.

While preferred embodiments have been shown and described, various modifications and substitutions may be made thereto without departing from the spirit and scope of the invention. Accordingly, it is to be understood that the present invention has been described by way of illustrations and not limitation.