TECHNICAL FIELD

The present invention generally relates to enhanced recovery of petroleum fluids from the subsurface by initiating and propagating vertical permeable inclusions in a plane substantially orthogonal to the borehole axis. These inclusions containing proppant are thus highly permeable and enhance drainage of heavy oil from the formation, and also by steam injection into these planes, enhance oil recovery by heating the oil sand formation, the heavy oil and bitumen, which will drain under gravity and be produced. The present invention generally relates to a method of isolating openings in an expanded casing to provide for fluid injection in a single longitudinal plane with the wellbore axis.

BACKGROUND OF THE INVENTION

Heavy oil and bitumen oil sands are abundant in reservoirs in many parts of the world such as those in Alberta, Canada, Utah and California in the United States, the Orinoco Belt of Venezuela, Indonesia, China and Russia. The hydrocarbon reserves of the oil sand deposit is extremely large in the trillions of barrels, with recoverable reserves estimated by current technology in the 300 billion barrels for Alberta, Canada and a similar recoverable reserve for Venezuela. These vast heavy oil (defined as the liquid petroleum resource of less than 20Â° API gravity) deposits are found largely in unconsolidated sandstones, being high porosity permeable cohensionless sands with minimal grain to grain cementation. The hydrocarbons are extracted from the oils sands either by mining or in situ methods.

The heavy oil and bitumen in the oil sand deposits have high viscosity at reservoir temperatures and pressures. While some distinctions have arisen between tar or oil sands, bitumen and heavy oil, these terms will be used interchangeably herein. The oil sand deposits in Alberta, Canada extend over many square miles and vary in thickness up to hundreds of feet thick. Although some of these deposits lie close to the surface and are suitable for surface mining, the majority of the deposits are at depth ranging from a shallow depth of 150 feet down to several thousands of feet below ground surface. The oil sands located at these depths constitute some of the world's largest presently known petroleum deposits. The oil sands contain a viscous hydrocarbon material, commonly referred to as bitumen, in an amount that ranges up to 15% by weight. Bitumen is effectively immobile at typical reservoir temperatures. For example at 15Â° C., bitumen has a viscosity of Ëœ1,000,000 centipoise. However at elevated temperatures the bitumen viscosity changes considerably to be Ëœ350 centipoise at 100Â° C. down to Ëœ10 centipoise at 180Â° C. The oil sand deposits have an inherently high permeability ranging from Ëœ1 to 10 Darcy, thus upon heating, the heavy oil becomes mobile and can easily drain from the deposit.

Solvents applied to the bitumen soften the bitumen and reduce its viscosity and provide a non-thermal mechanism to improve the bitumen mobility. Hydrocarbon solvents consist of vaporized light hydrocarbons such as ethane, propane or butane or liquid solvents such as pipeline diluents, natural condensate streams or fractions of synthetic crudes. The diluent can be added to steam and flashed to a vapor state or be maintained as a liquid at elevated temperature and pressure, depending on the particular diluent composition. While in contact with the bitumen, the saturated solvent vapor dissolves into the bitumen. This diffusion process is due to the partial pressure difference between the saturated solvent vapor and the bitumen. As a result of the diffusion of the solvent into the bitumen, the oil in the bitumen becomes diluted and mobile and will flow under gravity. The resultant mobile oil may be deasphalted by the condensed solvent, leaving the heavy asphaltenes behind within the oil sand pore space with little loss of inherent fluid mobility in the oil sands due to the small weight percent (5-15%) of the asphaltene fraction to the original oil in place. Deasphalting the oil from the oil sands produces a high grade quality product by 3Â°-5Â° API gravity. If the reservoir temperature is elevated the diffusion rate of the solvent into the bitumen is raised considerably being two orders of magnitude greater at 100Â° C. compared to ambient reservoir temperatures of Ëœ15Â° C.

In situ methods of hydrocarbon extraction from the oil sands consist of cold production, in which the less viscous petroleum fluids are extracted from vertical and horizontal wells with sand exclusion screens, CHOPS (cold heavy oil production system) cold production with sand extraction from vertical and horizontal wells with large diameter perforations thus encouraging sand to flow into the well bore, CSS (cyclic steam stimulation) a huff and puff cyclic steam injection system with gravity drainage of heated petroleum fluids using vertical and horizontal wells, steam flood using injector wells for steam injection and producer wells on 5 and 9 point layout for vertical wells and combinations of vertical and horizontal wells, SAGD (steam assisted gravity drainage) steam injection and gravity production of heated hydrocarbons using two horizontal wells, VAPEX (vapor assisted petroleum extraction) solvent vapor injection and gravity production of diluted hydrocarbons using horizontal wells, and combinations of these methods.

Cyclic steam stimulation and steam flood hydrocarbon enhanced recovery methods have been utilized worldwide, beginning in 1956 with the discovery of CSS, huff and puff or steam-soak in Mene Grande field in Venezuela and for steam flood in the early 1960s in the Kern River field in California. These steam assisted hydrocarbon recovery methods including a combination of steam and solvent are described in U.S. Pat. No. 3,739,852 to Woods et al, U.S. Pat. No. 4,280,559 to Best, U.S. Pat. No. 4,519,454 to McMillen, U.S. Pat. No. 4,697,642 to Vogel, and U.S. Pat. No. 6,708,759 to Leaute et al. The CSS process raises the steam injection pressure above the formation fracturing pressure to create fractures within the formation and enhance the surface area access of the steam to the bitumen. Successive steam injection cycles reenter earlier created fractures and thus the process becomes less efficient over time. CSS is generally practiced in vertical wells, but systems are operational in horizontal wells, but have complications due to localized fracturing and steam entry and the lack of steam flow control along the long length of the horizontal well bore.

Descriptions of the SAGD process and modifications are described in U.S. Pat. No. 4,344,485 to Butler, and U.S. Pat. No. 5,215,146 to Sanchez and thermal extraction methods in U.S. Pat. No. 4,085,803 to Butler, U.S. Pat. No. 4,099,570 to Vandergriji, and U.S. Pat. No. 4,116,275 to Butler et al. The SAGD process consists of two horizontal wells at the bottom of the hydrocarbon formation, with the injector well located approximately 10-15 feet vertically above the producer well. The steam injection pressures exceed the formation fracturing pressure in order to establish connection between the two wells and develop a steam chamber in the oil sand formation. Similar to CSS, the SAGD method has complications, albeit less severe than CSS, due to the lack of steam flow control along the long section of the horizontal well and the difficulty of controlling the growth of the steam chamber.

A thermal steam extraction process referred to a HASDrive (heated annulus steam drive) and modifications thereof heat and hydrogenate the heavy oils insitu in the presence of a metal catalyst. See U.S. Pat. No. 3,994,340 to Anderson el al., U.S. Pat. No. 4,696,345 to Hsueh, U.S. Pat. No. 4,706.751 to Gondouin. U.S. Patent No. 5,054,551 to Duerksen, and U.S. Pat. No. 5,145,003 to Duerksen. It is disclosed that at elevated temperature and pressure the injection of hydrogen or a combination of hydrogen and carbon monoxide to the heavy oil in situ in the presence of a metal catalyst will hydrogenate and thermal crack at least a portion of the petroleum in the formation.

Thermal recovery processes using steam require large amounts of energy to produce the steam, using either natural gas or heavy fractions of produced synthetic crude. Burning these fuels generates significant quantities of greenhouse gases, such as carbon dioxide. Also, the steam process uses considerable quantities of water, which even though may be reprocessed, involves recycling costs and energy use. Therefore a less energy intensive oil recovery process is desirable.

Solvents applied to the bitumen soften the bitumen and reduce its viscosity and provide a non-thermal mechanism to improve the bitumen mobility. Hydrocarbon solvents consist of vaporized light hydrocarbons such as ethane, propane or butane or liquid solvents such as pipeline diluents, natural condensate streams or fractions of synthetic crudes. The diluent can be added to steam and flashed to a vapor state or be maintained as a liquid at elevated temperature and pressure, depending on the particular diluent composition. While in contact with the bitumen, the saturated solvent vapor dissolves into the bitumen. This diffusion process is due to the partial pressure difference in the saturated solvent vapor and the bitumen. As a result of the diffusion of the solvent into the bitumen, the oil in the bitumen becomes diluted and mobile and will flow under gravity. The resultant mobile oil may be deasphalted by the condensed solvent, leaving the heavy asphaltenes behind within the oil sand pore space with little loss of inherent fluid mobility in the oil sands due to the small weight percent (5-15%) of the asphaltene fraction to the original oil in place. Deasphalting the oil from the oil sands produces a high grade quality product by 3Â°-5Â° API gravity. If the reservoir temperature is elevated the diffusion rate of the solvent into the bitumen is raised considerably being two orders of magnitude greater at 100Â° C. compared to ambient reservoir temperatures of Ëœ15Â° C.

Solvent assisted recovery of hydrocarbons in continuous and cyclic modes are described including the VAPEX process and combinations of steam and solvent plus heat. See U.S. Pat. No. 4,450,913 to Allen et al, U.S. Pat. No. 4,513,819 to Islip el al, U.S. Pat. No. 5,407,009 to Butler et al, U.S. Pat. No. 5,607,016 to Butler, U.S. Pat. No. 5,899,274 to Frauenfeld et al, U.S. Pat. No. 6,318,464 to Mokrys, U.S. Pat. No. 6,769,486 to Lirn et al, and U.S. Pat. No. 6,883,607 to Nenniger et al. The VAPEX process generally consists of two horizontal wells in a similar configuration to SAGD; however, there are variations to this including spaced horizontal wells and a combination of horizontal and vertical wells. The startup phase for the VAPEX process can be lengthy and take many months to develop a controlled connection between the two wells and avoid premature short circuiting between the injector and producer. The VAPEX process with horizontal wells has similar issues to CSS and SAGD in horizontal wells, due to the lack of solvent flow control along the long horizontal well bore, which can lead to non-uniformity of the vapor chamber development and growth along the horizontal well bore.

Direct heating and electrical heating methods for enhanced recovery of hydrocarbons from oil sands and oil shales have been disclosed in combination with steam, hydrogen, catalysts and/or solvent injection at temperatures to ensure the petroleum fluids gravity drain from the formation and at significantly higher temperatures (300Â° to 400Â° range and above) to pyrolysis the oil shales. See U.S. Pat. No. 2,780,450 to LjungstrÃ¶m, U.S. Pat. No. 4,597,441 to Ware et al, U.S. Pat. No. 4,926,941 to Glandt et al, U.S. Pat. No. 5,046,559 to Glandt, U.S. Pat, No. 5,060,726 to Glandt et al, U.S. Pat, No. 5,297,626 to Vinegar el al, U.S. Pat, No. 5,392,854 to Vinegar et al, U.S. Pat. No. 6,722,431 to Karanikas et al. In situ combustion processes have also been disclosed see U.S. Pat. No. 5,211,230 to Ostapovich et al, U.S. Pat. No. 5,339,897 to Leaute, U.S. Pat. No. 5,413,224 to Laali, and U.S. Pat. No. 5,954,946 to Klazinga et al.

In situ processes involving down hole heaters are described in U.S. Pat. No. 2,634,961 to LjungstrÃ¶m, U.S. Pat. No. 2,732,195 to LjungstrÃ¶m, U.S. Pat. No. 2,780,450 to LjungstrÃ¶m. Electrical heaters are described for heating viscous oils in the forms of downhole heaters and electrical heating of tubing and/or casing, see U.S. Pat. No. 2,548,360 to Germain, U.S. Pat. No. 4,716,960 to Eastlund et al, U.S. Pat. No. 5,060,287 to Van Egmond, U.S. Pat. No. 5,065,818 to Van Egmond, U.S. Pat. No. 6,023,554 to Vinegar and U.S. Pat. No. 6,360,819 to Vinegar. Flameless down hole combustor heaters are described, see U.S. Pat. No. 5,255,742 to Mikus, U.S. Pat. No. 5,404,952 to Vinegar et al, U.S. Pat. No. 5,862,858 to Wellington et al, and U.S. Pat. No. 5,899,269 to Wellington et al. Surface fired heaters or surface burners may be used to heat a heat transferring fluid pumped down hole to heat the formation as described in U.S. Pat. No. 6,056,057 to Vinegar et al and U.S. Pat. No. 6,079,499 to Mikus et al.

The thermal and solvent methods of enhanced oil recovery from oil sands, all suffer from a lack of surface area access to the in place bitumen. Thus the reasons for raising steam pressures above the fracturing pressure in CSS and during steam chamber development in SAGD, are to increase surface area of the steam with the in place bitumen. Similarly the VAPEX process is limited by the available surface area to the in place bitumen, because the diffusion process at this contact controls the rate of softening of the bitumen. Likewise during steam chamber growth in the SAGD process the contact surface area with the in place bitumen is virtually a constant, thus limiting the rate of heating of the bitumen. Therefore both methods (heat and solvent) or a combination thereof would greatly benefit from a substantial increase in contact surface area with the in place bitumen. Hydraulic fracturing of low permeable reservoirs has been used to increase the efficiency of such processes and CSS methods involving fracturing are described in U.S. Pat. No. 3,739,852 to Woods et al, U.S. Pat. No. 5,297,626 to Vinegar et al, and U.S. Pat. No. 5,392,854 to Vinegar et al. Also during initiation of the SAGD process over pressurized conditions are usually imposed to accelerate the steam chamber development, followed by a prolonged period of under pressurized condition to reduce the steam to oil ratio. Maintaining reservoir pressure during heating of the oil sands has the significant benefit of minimizing water inflow to the heated zone and to the well bore.

Electrical resistive heating of oil shale and oil sand formations utilizing a hydraulic fracture filled with an electrically conductive material are described in U.S. Pat. No. 3,137,347 to Parker, involving a horizontal hydraulic fracture filled with conductive proppant and with the use of two (2) wells to electrically energizing the fracture and raise the temperature of the oil shale to pyrolyze the organic matter and produce hydrocarbon from a third well, in U.S. Pat. No. 5,620,049 to Gipson et al. with a single well configuration in a hydrocarbon formation predominantly a vertical fracture filled with conductive temperature setting resin coated proppant and the electric current passes through the conductive proppant to a surface ground and the single well is completed to raise the temperature of the oil in-situ to reduce its viscosity and produce hydrocarbons from the same well, in U.S. Pat. No. 6,148,911 to Gipson et al. with a single well configuration in a gas hydrate formation with predominantly a horizontal fracture filled with conductive proppant and the electric current passes through the conductive proppant to a surface ground, raising the temperature of the formation to release the methane from the gas hydrates and the single well is completed for methane production, in U.S. Pat. No. 7,331,385 to Symington et al. in U.S. Pat. No. 7,631,691 to Symington et al. and in Canadian Patent No. 2,738,873 to Symington et al. all with a predominantly vertical fracture filled with conductive proppant and the conductive fracture is electrically energized by contact with at least two (2) wells or in the case of a single well presumably through the well and surface ground with the oil shale raised to a temperature to pyrolyze the organic matter into producible hydrocarbons, with the electrically conductive fracture composed of electrically conductive proppant and non-electrically conductive non-permeable cement. The single well systems described above all suffer from low efficiency and high energy loss due to the current passes through a significant distance of the formation from the conductive fracture to the surface ground. Also the systems with two or more wellbores do not disclosed how the electrode to conductive fracture contact will be other than a point contact resulting in significant energy loss and overheating at such a contact.

It is well known that extensive heavy oil reservoirs are found in formations comprising unconsolidated, weakly cemented sediments. Unfortunately, the methods currently used for extracting the heavy oil from these formations have not produced entirely satisfactory results. Heavy oil is not very mobile in these formations, and so it would be desirable to be able to form increased permeability planes in the formations and by injecting steam or solvents into these planes and/or by direct electrical resistive heating of the plane, heating the formation and thus increase the mobility of the heavy oil in the formation and by drainage through the permeable planes to the wellbore for production up the well. Steam injection into multiple azimuth vertical permeables planes has been disclosed earlier in U.S. Pat. No. 7,591,306 to Hocking; however the method cited is for a single well being both a steam injector and liquids producer, whereas the current invention contains multiple wells with the significant advantage of much faster production and lower steam to oil ratio (SOR).

However, techniques used in hard, brittle rock to form fractures therein are typically not applicable to ductile formations comprising unconsolidated, weakly cemented sediments. The method of controlling the azimuth of a vertical hydraulic planar inclusion in formations of unconsolidated or weakly cemented soils and sediments by slotting the well bore or installing a pre-slotted or weakened casing at a predetermined azimuth has been disclosed. The method disclosed that a vertical hydraulic planar inclusion can be propagated at a pre-determined azimuth in unconsolidated or weakly cemented sediments and that multiple orientated vertical hydraulic planar inclusions at differing azimuths from a single well bore can be initiated and propagated for the enhancement of petroleum fluid production from the formation. See U.S. Pat. No. 6,216,783 to Hocking et al, U.S. Pat. No. 6,443,227 to Hocking et al, U.S. Pat. No. 6,991,037 to Hocking, U.S. Pat. No. 7,404,441 to Hocking, U.S. Pat. No. 7,640,975 to Cavender et al., U.S. Pat. No. 7,640,982 to Schultz et al., U.S. Pat. No. 7,748,458 to Hocking, U.S. Pat. No. 7,814,978 to Steele et al., U.S. Pat. No. 7,832,477 to Cavender et al., U.S. Pat. No. 7,866,395 to Hocking, U.S. Pat. No. 7,950,456 to Cavender et al., U.S. Pat. No. 8,151,874 to Schultz et al. The method disclosed that a vertical hydraulic planar inclusion can be propagated at a pre-determined azimuth in unconsolidated or weakly cemented sediments and that multiple orientated vertical hydraulic planar inclusions at differing azimuths from a single well bore can be initiated and propagated for the enhancement of petroleum fluid production from the formation. It is now known that unconsolidated or weakly cemented sediments behave substantially different from brittle rocks from which most of the hydraulic fracturing experience is founded. The above cited, U.S. Pat. No. 6,991,037 to Hocking, and U.S. Pat. No. 7,748,458 to Hocking, disclose a method to create a planar inclusion by selectively injecting the fluid into a single plane on a particular azimuth, via ports and channels that connect to each discrete plane. It is preferable to remove such ports and channels from the casing construction and thus provide for a smaller diameter casing; whilst still maintaining selective injection of the fluid into a single plane on a particular plane.

The methods disclosed above find especially beneficial application in ductile rock formations made up of unconsolidated or weakly cemented sediments, in which it is typically very difficult to obtain directional or geometric control over inclusions as they are being formed. Weakly cemented sediments are primarily frictional materials since they have minimal cohesive strength. An uncemented sand having no inherent cohesive strength (i.e., no cement bonding holding the sand grains together) cannot contain a stable crack within its structure and cannot undergo brittle fracture. Such materials are categorized as frictional materials which fail under shear stress, whereas brittle cohesive materials, such as strong rocks, fail under normal stress.

The term â€œcohesionâ€ is used in the art to describe the strength of a material at zero effective mean stress. Weakly cemented materials may appear to have some apparent cohesion due to suction or negative pore pressures created by capillary attraction in fine grained sediment, with the sediment being only partially saturated. These suction pressures hold the grains together at low effective stresses and, thus, are often called apparent cohesion.

The suction pressures are not true bonding of the sediment's grains, since the suction pressures would dissipate due to complete saturation of the sediment. Apparent cohesion is generally such a small component of strength that it cannot be effectively measured for strong rocks, and only becomes apparent when testing very weakly cemented sediments.

Geological strong materials, such as relatively strong rock, behave as brittle materials at normal petroleum reservoir depths, but at great depth (i.e. at very high confining stress) or at highly elevated temperatures, these rocks can behave like ductile frictional materials. Unconsolidated sands and weakly cemented formations behave as ductile frictional materials from shallow to deep depths, and the behavior of such materials are fundamentally different from rocks that exhibit brittle fracture behavior. Ductile frictional materials fail under shear stress and consume energy due to frictional sliding, rotation and displacement.

Conventional hydraulic dilation of weakly cemented sediments is conducted extensively on petroleum reservoirs as a means of sand control. The procedure is commonly referred to as

â€œFrac-and-Pack.â€ In a typical operation, the casing is perforated over the formation interval intended to be fractured and the formation is injected with a treatment fluid of low gel loading without proppant, in order to form the desired two winged structure of a fracture. Then, the proppant loading in the treatment fluid is increased substantially to yield tip screen-out of the fracture. In this manner, the fracture tip does not extend further, and the fracture and perforations are backfilled with proppant.

The process assumes a two winged fracture is formed as in conventional brittle hydraulic fracturing. However, such a process has not been duplicated in the laboratory or in shallow field trials. In laboratory experiments and shallow field trials what has been observed is chaotic geometries of the injected fluid, with many cases evidencing cavity expansion growth of the treatment fluid around the well and with deformation or compaction of the host formation.

Weakly cemented sediments behave like a ductile frictional material in yield due to the predominantly frictional behavior and the low cohesion between the grains of the sediment. Such materials do not â€œfractureâ€ and, therefore, there is no inherent fracturing process in these materials as compared to conventional hydraulic fracturing of strong brittle rocks.

Linear elastic fracture mechanics is not generally applicable to the behavior of weakly cemented sediments. The knowledge base of propagating viscous planar inclusions in weakly cemented sediments is primarily from recent experience over the past ten years and much is still not known regarding the process of viscous fluid propagation in these sediments.

Accordingly, there is a need for a method and apparatus for enhancing the extraction of hydrocarbons from oil sands via permeable vertical inclusions installed in the formation, and selectively injecting a fluid into each discrete plane on a particular azimuth without the necessity for ports and channels to be in the casing section.

SUMMARY OF THE INVENTION

The present invention is a method and apparatus for enhanced recovery of petroleum fluids from the subsurface by initiating and propagating vertical permeable inclusions in a plane substantially orthogonal to the borehole axis. These inclusions containing proppant are thus highly permeable and enhance drainage of heavy oil from the formation, and also by steam injection into these planes, enhance oil recovery by heating the oil sand formation, the heavy oil and bitumen, which will drain under gravity and be produced. In one embodiment of this invention, multiple propped vertical inclusions are constructed at various azimuths from a well by expansion of a casing section and propagating the proppant filled inclusions into the oil sand formation. The vertical inclusions are propagated discretely by selectively injecting fluid into each plane independent of the other planes, without the need for ports and channels to be constructed in the casing.

Although the present invention contemplates the formation of vertical propped inclusions which generally extend laterally away from a vertical or near vertical well penetrating an earth formation and in a generally vertical plane, those skilled in the art will recognize that the invention may be carried out in earth formations wherein the fractures and the well bores can extend in directions other than vertical.

Other objects, features and advantages of the present invention will become apparent upon reviewing the following description of the preferred embodiments of the invention, when taken in conjunction with the drawings and the claims.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic isometric view of a well system and associated method embodying principles of the present invention;

FIG. 2 is a schematic isometric view of a well system and associated method of the treatment tool in a section of the well casing;

FIG. 3 is a horizontal cross-sectional view of the wing isolation device in an expanded section of the casing;

FIG. 4 is a horizontal cross-sectional view of the wing isolation device in an expanded section of the casing and with fluid injection into a single plane.

DETAILED DESCRIPTION OF THE DISCLOSED EMBODIMENT

Several embodiments of the present invention are described below and illustrated in the accompanying drawings. The present invention involves a method and apparatus for enhanced recovery of petroleum fluids from the subsurface by construction of propped vertical inclusions in the oil sand formation from a substantially vertical wellbore for enhancing drainage of heavy oil from the formation and/or to provide a means of injecting fluid into each discrete plane independent of other planes on differing azimuths, by injection isolation of the discrete plane by a wing isolation device contained within a treatment tool lowered into the well.

Representatively illustrated in FIG. 1 is a well system 10 and associated method which embody principles of the present invention. The system 10 is particularly useful for producing heavy oil 42 from a formation 14. The formation 14 may comprise unconsolidated and/or weakly cemented sediments for which conventional fracturing operations are not well suited. The term â€œheavy oilâ€ is used herein to indicate relatively high viscosity and high density hydrocarbons, such as bitumen. Heavy oil is typically not recoverable in its natural state (e.g., without heating or diluting) via wells, and may be either mined or recovered via wells through use of steam and solvent injection, in situ combustion, etc. Gas-free heavy oil generally has a viscosity of greater than 100 centipoise and a density of less than 20 degrees API gravity (greater than about 900 kilograms/cubic meter).

As depicted in FIG. 1, a substantially vertical well has been drilled into the formation 14 and the well casing 11 has been cemented in the formation 14 or is in contact with the formation by a swellable elastomer. The term â€œcasingâ€ is used herein to indicate a protective lining for a wellbore. Any type of protective lining may be used, including those known to persons skilled in the art as liner, casing, tubing, etc. Casing may be segmented or continuous, jointed or unjointed, conductive or non-conductive made of any material (such as steel, aluminum, polymers, composite materials, etc.), and may be expanded or unexpanded, etc.

The well casing string 11 has expansion devices 12 and a sump section 40 interconnected therein. The expansion device 12 operates to expand the casing string 11 radially outward and thereby dilate the formation 14 proximate the device, in order to initiate forming of generally vertical and planar inclusions 18 extending outwardly from the wellbore at various azimuths. Suitable expansion devices 12 for use in the well system 10 are described in U.S. Pat. Nos. 6,216,783, 6,330,914, 6,443,227, 6,991,037, 7,404,441, 7,640,975, 7,640,982, 7,748,458, 7,814,978, 7,832,477, 7,866,395, 7,950,456 and 8,151,874. The entire disclosures of these prior patents are incorporated herein by this reference. Other expansion devices may be used in the well system 10 in keeping with the principles of the invention.

Once the device 12 is operated to expand the casing string 11 radially outward, fluid 22 is forced into the dilated formation 14 to propagate the inclusions 18 into the formation. It is not necessary for the inclusions 18 to be formed simultaneously. Shown in FIG. 1 is an eight (8) wing inclusion well system 10, with eight (8) inclusions 18 formed. The well system 10 does not necessarily need to consist of eight (8) inclusions at the same depth orientated at various azimuths, but could consist of one, two, three, four, five, six or even seven vertical planar inclusions at various azimuths at the same depth, with such choice of the number of inclusions constructed depending on the application, formation type and/or economic benefit. Also there are upper inclusions on the same azimuth, and in fact there could be numerous of these upper inclusions at progressively shallower depths, or there could only be a single inclusion at a particular depth.

Typically, the lower inclusions 18 are constructed first, with each wing of the eight (8) inclusions 18 injected independently of the others. The formation 14, pore space may contain a significant portion of immobile heavy oil or bitumen generally up to a maximum oil saturation of 90%; however, even at these very high oil saturations of 90%, i.e. very low water saturation of 10%, the mobility of the formation pore water is quite high, due to its viscosity and the formation permeability. The injected fluid 22 carries the proppant to the extremes of the inclusions 18. Upon propagation of the inclusions 18 to their required lateral and vertical extent, the thickness of the inclusions 18 may need to be increased by utilizing the process of tip screen out. The tip screen out process involves modifying the proppant loading and/or inject fluid 22 properties to achieve a proppant bridge at the inclusion tips. The injected fluid 22 is further injected after tip screen out, but rather then extending the inclusion laterally or vertically, the injected fluid 22 widens, i.e. thickens, and fills the inclusion from the inclusion tips back to the well bore.

The behavioral characteristics of the injected viscous fluid 22 are preferably controlled to ensure the propagating viscous inclusions maintain their azimuth directionality, such that the viscosity of the injected fluid 22 and its volumetric rate are controlled within certain limits depending on the formation 14, proppant 20 specific gravity and size distribution. For example, the viscosity of the injected fluid 22 is preferably greater than approximately 100 centipoise.

However, if foamed fluid is used, a greater range of viscosity and injection rate may be permitted while still maintaining directional and geometric control over the inclusions. The viscosity and volumetric rate of the injected fluid 22 needs to be sufficient to transport the proppant 20 to the extremities of the inclusions. The size distribution of the proppant 20 needs to be matched with that of the formation 14, to ensure formation fines do not migrate into the propped pack inclusion during hydrocarbon production. Typical size distribution of the proppant would range from #12 to #20 U.S. Mesh for oil sand formations, with an ideal proppant being sand or ceramic beads. Ceramic beads coated with a resin such as phenol formaldehyde, being heat hardenable, is capable of mechanically binding the proppant together 21 in the presence of steam without loss of permeability of the propped inclusion.

In the well system 10, heavy oil 42 will flow under gravity through the inclusions and the formation towards the well and enter the sump 40 and is pumped to surface via a PCP (progressive cavity pump), ESP (electrical submersible pump), gas lift or natural lift 41, depending on operating temperatures, pressures and depth, via a production tubing 40. As depicted in FIG. 2, is a configuration of the well system 10, after radial expansion of the casing 11 by expansion device 12 in a section of the well with the expanded casing section shown 11â€². The well system 10 is conveyed on tubing or drill pipe 13 and upward and downward facing cups 19 are position to straddle the expanded section 11â€². The slot isolation elements 15 are orientated to the azimuth of the inclusion 18 to be propagated by fluid injection 22, containing proppant 20. The straddle cups 19 and the slot isolation elements 15 consists of an elastomer, such as rubber, reinforced and molded onto steel base to form a flexible but strong system for fluid isolation. Such straddle cups 19 are currently in common use in the stimulation of wells for hydrocarbon production.

As depicted in FIG. 3, is a horizontal cross-section of the well system 10, after radial expansion of the casing 11 by expansion device 12 in a section of the well results in an expanded casing section shown 11â€², with slots 24 opening in the sidewall of the casing 11 during expansion. The slot isolation elements 15 are orientated to the azimuth 23 of the inclusion to be propagated. In FIG. 3 there are six (6) sets of slots 24 at various azimuths, whereas there could be any number of sets of slots 24 depending on the application and could be two (2) sets or more. Each set of slots 24 as shown consist of three (3) individual slots 24, where there could be any number of individual slots 24 in a set of slots. The slot isolation elements 15 are shown as three (3) sets for isolation over three (3) sets of slots 24 at three (3) differing azimuths 23. There could be only a single set of slot isolation elements 15 for isolation across a single set of slots 24 on a particular azimuth 23. The number of slot isolation element 15 contained in the well system 10 will depend on the number of inclusions that are to be formed at differing azimuths at a particular depth. Each set of slot isolation elements 15 are connected to a fluid injection tubing 17 via an opening 16.

As depicted in FIG. 4, is a horizontal cross-section of the well system 10, after radial expansion of the casing 11 by expansion device 12 in a section of the well resulting in the expanded casing section shown 11â€², with slots 24 opening in the sidewall of the casing 11 during expansion. The slot isolation elements 15 are orientated to the azimuth 23 of the inclusion to be propagated. Fluid 22 is injected through tubing 17 contained within the well tubing 13 through opening 16 into the formation 14 through slots 24 on a particular azimuthal plane 23. The slot isolation elements 15â€² deform to seal against the casing 11, 11â€² and isolate the slots 24 along the azimuth 23 from the remaining sets of slots 24. Upon completion of fluid 22 injection for planar inclusion on a particular azimuth 23, sequentially another set of slots 24 can be injected with fluid via other tubing and opening shown for three (3) sets of slot isolation elements 15. Subsequently, the isolation elements 15 could be rotated 60Â° and thus inject in the other three (3) sets of slots 12 shown.

The formation 14 could be comprised of relatively hard and brittle rock, but the system 10 and method find especially beneficial application in ductile rock formations made up of unconsolidated or weakly cemented sediments, in which it is typically very difficult to obtain directional or geometric control over inclusions as they are being formed. However, the present disclosure provides information to enable those skilled in the art of hydraulic fracturing, soil and rock mechanics to practice a method and system 10 to initiate and control the propagation of a viscous fluid in weakly cemented sediments, and importantly for the fluid to be injected in a specific discrete plane in the formation without the necessity of having ports and channels in the casing string.

Finally, it will be understood that the preferred embodiment has been disclosed by way of example, and that other modifications may occur to those skilled in the art without departing from the scope and spirit of the appended claims.