System and methods for injection and production from a single wellbore

Methods and systems of treating hydrocarbon containing formations are described herein. A system for treating a subterranean hydrocarbon containing formation includes a wellbore, and one or more packers positioned in the wellbore. At least one of the packers allows fluid to be injected in a subterranean hydrocarbon containing formation while allowing fluid to be produced from the wellbore.

BACKGROUND

1. Field of the Invention

The present invention relates generally to methods and systems for production of hydrocarbons and/or other products from various subsurface formations such as hydrocarbon containing formations.

2. Description of Related Art

Hydrocarbons obtained from subterranean formations are often used as energy resources, as feedstocks, and as consumer products. Concerns over depletion of available hydrocarbon resources and concerns over declining overall quality of produced hydrocarbons have led to development of processes for recovery that is more efficient, processing and/or use of available hydrocarbon resources. In-situ processes may be used to remove hydrocarbon materials from subterranean formations that were previously inaccessible and/or too expensive to extract using available methods.

Substantial reserves of hydrocarbons exist in formations that have relatively low permeability. Examples of such formations include the Eagle Ford shale, the Barnett shale, the Travis Peak and Cotton Valley formations and the Bakken shale. Several methods have been proposed and/or used for producing heavy hydrocarbons from relatively low permeability formations. Recovery of hydrocarbons from low permeability subterranean formations is difficult because of the low mobility of fluids in the pore space in the subterranean formation (ultra-low permeability rocks). This makes the production and injection of fluids from such reservoirs very difficult. Similar problems are encountered in heavy oil reservoirs (reservoirs containing crude oil with a viscosity larger than about 100 centipoise). Mobility of the fluids in heavy oil reservoirs is small, and thus, injecting and producing from such hydrocarbon bearing rock is difficult.

U.S. Pat. No. 5,289,881 to Schuh describes a horizontal well completion apparatus and method for heavy, viscous oil in a producing zone using a single well. Hot injection fluid is injected into an injection string, reduced to a lower pressure by passing the injection fluid through a choke. A packer separates the upper well annulus from the lower well annulus. Insulation surrounds injection tubing string between the packer and the wellhead. Perforations in the horizontal portion of the well allow heated oil to flow into the lower annulus in the horizontal portion of the well where is picked up by the injected fluid and lifted to the surface of the well by a jet pump. The temperature and pressure of the injection fluid, and the pumping rate of the produced fluids control temperature and pressure in the lower well annulus.

Oil recovery by primary production (hydrocarbon production accomplished using the natural energy in the reservoir) is usually very low for unconventional oil and gas reservoirs. In unconventional reservoirs such as the Bakken and Eagle Ford formations, typical primary production is about 5% of the original oil in place compared to 15 to 25% in permeable subterranean formations. Thus, a very large resource of hydrocarbons is left unrecovered.

In conventional (high permeability) reservoirs, water injection and enhanced oil recovery methods such as CO2flooding and chemical injection are used to recover additional hydrocarbons. The use of these methods is restricted by the inability to inject at sufficiently high rates into low permeability or heavy oil reservoirs. During injection processes, the injection pressures is limited as the subterranean formation will fracture once the fracture gradient of the rock is exceeded. Since the injection pressure and/or rate is limited, injection of fluids takes time and may have little to no impact on hydrocarbon production. For example, in a chemical flooding process, a minimum of 0.25 times the hydrocarbon pore volume of the reservoir area being flooded may be required to see any incremental oil recovery. In low permeability formations, achieving this may take many decades (or at least many years).

Although, there has been a significant amount of effort to develop methods and systems to produce hydrocarbons and/or other products from relatively low permeability formations, there is still a need for improved methods and systems for production of hydrocarbons.

SUMMARY

Methods and systems of treating hydrocarbon containing formations are described herein. In some embodiments, a system for treating a subterranean hydrocarbon containing formation includes a wellbore in the subterranean hydrocarbon containing formation; a first packer positioned in the wellbore, wherein the first packer allows fluid to be injected in a subterranean hydrocarbon containing formation; and a second packer positioned in the wellbore and in fluid communication with the first packer, wherein the second packer allows fluid to be produced from the wellbore, and is in fluid communication with the first packer.

In some embodiments, a method for treating a subterranean hydrocarbon containing formation includes providing a substantially horizontal or deviated wellbore to a subterranean hydrocarbon containing formation; providing a plurality of packers to the substantially horizontal or deviated wellbore; providing injection fluid to at least a first section of the hydrocarbon and/or a second section of the containing formation through at a first packer and/or a second packer; and mobilizing hydrocarbons from at least a third section of the hydrocarbon containing formation through a third packer, wherein the third section of the hydrocarbon containing formation is between the first and second section of the hydrocarbon containing formation.

In some embodiments, a method for injecting and producing from a single wellbore in a subterranean hydrocarbon containing formation includes providing injection fluid to at least a first section of the hydrocarbon containing formation from a wellbore in the subterranean hydrocarbon containing formation; mobilizing formation fluids from the first section to a second section of the hydrocarbon formation, the second section being located substantially adjacent to the first section and at least partially horizontally displaced from the first section, and producing the mobilized fluid from second section through the wellbore.

In some embodiments, a method for injecting and producing from a single wellbore in a subterranean hydrocarbon containing formation includes providing a substantially horizontal or deviated wellbore to a subterranean hydrocarbon containing formation; providing a plurality of packers to the substantially horizontal or deviated wellbore, wherein a first packer is horizontally displaced from a second packer of the plurality of packers; providing injection fluid to at least a first section of the hydrocarbon containing formation through the first packer in a first portion of the wellbore; mobilizing hydrocarbons from the first section of the hydrocarbon formation to a second portion of the wellbore, wherein the second portion of the wellbore comprises a second packer in fluid communication with the first packer, and producing the mobilized hydrocarbons from the wellbore.

In some embodiments, a method for injecting and producing from a single wellbore in a subterranean hydrocarbon containing formation includes providing a substantially horizontal or deviated wellbore to a subterranean hydrocarbon containing formation; providing a plurality of packers to the substantially horizontal or deviated wellbore, wherein a first packer is horizontally displaced from a second packer of the plurality of packers; providing injection fluid to at least a first section of the hydrocarbon containing formation by flowing injection fluid through the first packer; and mobilizing hydrocarbons from the first section of the hydrocarbon formation to a second section of the wellbore, wherein the second section of the wellbore comprises a second packer in fluid communication with the first packer, and producing the mobilized fluid from the wellbore.

In some embodiments, a method for injecting and producing from a single wellbore in a subterranean hydrocarbon containing formation includes providing a substantially horizontal or deviated wellbore to a subterranean hydrocarbon containing formation; providing a plurality of packers to the substantially horizontal or deviated wellbore, wherein a first packer is horizontally displaced from a second packer of the plurality of packers; providing injection fluid to at least a first section of the hydrocarbon containing formation by flowing injection fluid through the first packer; and mobilizing hydrocarbons from at least a second section of the hydrocarbon containing formation through the second packer, and producing the mobilized fluid from the wellbore.

In some embodiments, a method for injecting and producing from a single wellbore in a subterranean hydrocarbon containing formation includes providing a wellbore to the hydrocarbon containing formation, wherein the wellbore includes perforations; opening and/or closing at least some of the perforations adjacent to at least a first section and/or at least third section of the hydrocarbon containing formation to inject or inhibit injection fluid to at least the first section and/or at least the third section of the hydrocarbon containing formation; mobilizing formation fluids from the at least first section and/or the at least third section to at least a second section and/or at least a fourth section of the hydrocarbon containing formation; opening and/or closing at least some of the perforations adjacent to the second section and/or the fourth section to allow or to inhibit the mobilized formation fluids to flow into at least a portion of the of the wellbore adjacent to the second section and/or the fourth section of the hydrocarbon containing formation; and producing the formation fluids through the wellbore.

In some embodiments, a method for producing fractures in a subterranean hydrocarbon containing formation using a single wellbore includes providing a fluid to a wellbore in the subterranean hydrocarbon containing formation, wherein the wellbore includes covered perforations adjacent to at least three sections of the hydrocarbon formation, and wherein the perforations are separated by at least one packer; opening at least some of the perforations to allow fluid to enter the first section of the hydrocarbon containing formation; pressurizing the fluid to form fractures in the first section of the hydrocarbon containing formation; opening at least some of the perforations to allow fluid to enter a second section of the hydrocarbon containing formation; pressurizing the fluid to form fractures in the second section of the hydrocarbon containing formation; opening at least some of the perforations to allow fluid to enter a third section of the hydrocarbon containing formation; and pressurizing the fluid to form fractures in the third section of the hydrocarbon containing formation, wherein the third section is between the first and second sections.

A system for treating a subterranean hydrocarbon containing formation includes a wellbore in the subterranean hydrocarbon containing formation; a plurality of packers positioned in the wellbore, wherein the packers are in fluid communication with an annulus of the wellbore, and wherein at least two packers inhibit fluid communication between a portion of the wellbore annulus positioned between the two packers of the plurality of packers and a portion the wellbore annulus adjoining at least one of the packers

In further embodiments, features from specific embodiments may be combined with features from other embodiments. For example, features from one embodiment may be combined with features from any of the other embodiments.

In further embodiments, additional features may be added to the specific embodiments described herein.

DETAILED DESCRIPTION

The following description generally relates to systems and methods for treating hydrocarbons in the formations. Such formations may be treated to yield hydrocarbon products and other products.

“API gravity” refers to API gravity at 15.5° C. (60° F.). API gravity is as determined by ASTM Method D6822 or ASTM Method D1298.

A “fluid” may be, but is not limited to, a gas, a liquid, an emulsion, a slurry, and/or a stream of solid particles that has flow characteristics similar to liquid flow.

A “formation” includes one or more hydrocarbon containing layers, one or more non-hydrocarbon layers, an overburden, and/or an underburden. “Hydrocarbon layers” refer to layers in the formation that contain hydrocarbons. The hydrocarbon layers may contain non-hydrocarbon material and hydrocarbon material. The “overburden” and/or the “underburden” include one or more different types of impermeable materials. For example, the overburden and/or underburden may include rock, shale, mudstone, or wet/tight carbonate.

“Formation fluids” refer to fluids present in a formation and may include gases and liquids produced from a formation. Formation fluids may include hydrocarbon fluids as well as non-hydrocarbon fluids. Examples of formation fluids include inert gases, hydrocarbon gases, carbon oxides, mobilized hydrocarbons, water (steam), and mixtures thereof. The term “mobilized fluid” refers to fluids in a hydrocarbon containing formation that are able to flow as a result of thermal treatment of the formation. “Produced fluids” refer to fluids removed from the formation.

“Fracture” refers to a crack or surface of breakage within a rock. A fracture along which there has been lateral displacement may be termed a fault. When walls of a fracture have moved only normal to each other, the fracture may be termed a joint. Fractures may enhance permeability of rocks greatly by connecting pores together, and for that reason, joints and faults may be induced mechanically in some reservoirs in order to increase fluid flow.

“Heavy hydrocarbons” are viscous hydrocarbon fluids. Heavy hydrocarbons may include highly viscous hydrocarbon fluids such as heavy oil, tar, oil sands, and/or asphalt. Heavy hydrocarbons may include carbon and hydrogen, as well as smaller concentrations of sulfur, oxygen, and nitrogen. Additional elements may also be present in heavy hydrocarbons in trace amounts. Heavy hydrocarbons may be classified by API gravity. Heavy hydrocarbons generally have an API gravity below about 20°. Heavy oil, for example, generally has an API gravity of about 10-20°, whereas tar generally has an API gravity below about 10°. The viscosity of heavy hydrocarbons is generally greater than about 100 centipoise at 15° C. Heavy hydrocarbons may include aromatics or other complex ring hydrocarbons.

Heavy hydrocarbons may be found in a relatively permeable formation. The relatively permeable formation may include heavy hydrocarbons entrained in, for example, sand, or carbonate. “Relatively permeable” is defined, with respect to formations or portions thereof, as an average permeability of 10 millidarcy or more (for example, 10 or 100 millidarcy). “Relatively low permeability” is defined, with respect to formations or portions thereof, as an average permeability of less than about 10 millidarcy. One darcy is equal to about 0.99 square micrometers. A low permeability layer generally has a permeability of less than about 0.1 millidarcy.

“Hydrocarbons” are generally defined as molecules formed primarily by carbon and hydrogen atoms. Hydrocarbons may also include other elements such as, but not limited to, halogens, metallic elements, nitrogen, oxygen, and/or sulfur. Hydrocarbons may be, but are not limited to, kerogen, bitumen, pyrobitumen, oils, natural mineral waxes, and asphaltites. Hydrocarbons may be located in or adjacent to mineral matrices in the earth. Matrices may include, but are not limited to, sedimentary rock, sands, silicilytes, carbonates, diatomites, and other porous media. “Hydrocarbon fluids” are fluids that include hydrocarbons. Hydrocarbon fluids may include, entrain, or be entrained in non-hydrocarbon fluids such as hydrogen, nitrogen, carbon monoxide, carbon dioxide, hydrogen sulfide, water, and ammonia.

“Hydraulic fracturing” refers to creating or opening fractures that extend from the wellbore into formations. A fracturing fluid, typically viscous, may be injected into the formation with sufficient hydraulic pressure (for example, at a pressure greater than the lithostatic pressure of the formation) to create and extend fractures, open preexisting natural fractures, or cause slippage of faults. In the formations discussed herein, natural fractures and faults may be opened by pressure. A proppant may be used to “prop” or hold open the fractures after the hydraulic pressure has been released. The fractures may be useful for allowing fluid flow, for example, through a shale formation, or a geothermal energy source, such as a hot dry rock layer, among others.

“Perforations” include openings, slits, apertures, or holes in a wall of a conduit, tubular, pipe or other flow pathway that allow flow into or out of the conduit, tubular, pipe or other flow pathway.

“Packers” include any kind of device placed inside a wellbore that isolates the injection fluid from the production fluid and directs these fluids to either an annulus or one or more tubing strings. Multiple packers may be placed inside a wellbore.

The term “wellbore” refers to a hole in a formation made by drilling or insertion of a conduit into the formation. A wellbore may have a substantially circular cross section, or another cross-sectional shape. The wellbore may be open-hole or may be cased and cemented. As used herein, the terms “well” and “opening,” when referring to an opening in the formation may be used interchangeably with the term “wellbore.” “Horizontal wellbore” refers to a portion of a wellbore in a subterranean hydrocarbon containing formation to be completed that is substantially horizontal or deviated at an angle from horizontal in the range of from about 0° to about 15°.

Recovery of hydrocarbons may be more economically feasible in low permeability reservoirs by improving the ability to inject into a formation (for example, reservoir) and to reduce the volume of the formation (for example, reservoir) that is being impacted by any injection or production location in the wellbore. Reducing the volume of formation may reduce the time needed to recover hydrocarbons. Thus, conventional recovery methods may be practical to use in low permeability subterranean formations. Multiple injection and production locations along a single wellbore may effectively break up the formation (from which hydrocarbons are being produced) into smaller volumetric pieces, and increases the total injection and production rate, if these wellbore locations are hydraulically fractured. For example, in a conventional reservoir, with a modest permeability of 10 millidarcy and a porosity of 20%, injection into a 50 feet thick reservoir at 1000 bbl/day would take 1 year to inject 0.25 pore volume of fluid. If the permeability were to be decreased to 0.01 millidarcy, the injection rate would drop by 1,000 times and it would take 1,000 years to inject 0.25 pore volume of fluid. If, however, 50 locations or points of injection and/or production were available along a wellbore, the ability to inject and/or produce at about 50 times the rate may be possible from the single wellbore, and the area (and pore volume) that needs to be flooded per injection point is reduced by 50 times. Thus, the target injection volume may be reached in less than 20 years. In some embodiments, hydraulically fracturing an injection location or set of locations would increase the injection area of the formation by a factor of 100. Thus, allowing injection of more water, gas, heat, and/or improving hydrocarbon recovery chemical in about 1 or 2 years. In addition, injected fluids may more efficiently contact and displace the hydrocarbons. The incorporation of multiple injection and production points in a single wellbore, therefore, allows improved recovery methods to be more efficiently applicable in low permeability reservoirs.

Heavy oil reservoirs where the oil viscosity is many orders of magnitude higher than conventional oil reservoirs may be treated in the same manner. Production and injection of fluids is limited due to high fluid viscosity. In conventional methods, injection and production from a low permeability formation takes a long time and the fluid rates are typically low. Thus, conventional processes may be deemed uneconomical.

Injecting fluids at a higher temperature leads to a decrease in viscosity of the hydrocarbon fluids in the reservoir. Thus, volumetrically dividing the reservoir into various segments may lead to an increase in the contact area of the hot injection fluid with the formation fluid. The use of multiple injection and production points from a single wellbore, therefore, may facilitate more recovery of hydrocarbon from these heavy oil reservoirs.

A hydrocarbon containing formation may be treated using enhanced oil recovery methods (for example, a chemical injection process, a water injection process, a gas injection process and/or a steam injection process). Injection fluid may be provided to the formation. The injected fluid may displace, miscible or immiscibly, hydrocarbons towards the production wellbore by reducing the viscosity, reducing the interfacial tension of the fluids, solubilizing or emulsifying the hydrocarbons in the formation. Reduction in the viscosity allows the fluid to more easily drain and be produced from the production wellbore.

In a conventional injection or production process, fluid injection may not treat the formation uniformly. For example, steam injection may not be uniform throughout the formation. Chemicals may move selectively in high permeability channels. Gravity segregation will occur when CO2or hydrocarbon gases are injected. Variations in the properties of the formation (for example, fluid injectivities, permeabilities, and/or porosities) may result in non-uniform injection of the injection fluid through the formation. Because of the non-uniform injection of the injection fluid (for example, steam), the injection fluid may remove hydrocarbons from different portions of the formation at different rates or with different results. For example, some portions of the formation may have little or no fluid injectivity, which inhibits the hydrocarbon production from these portions. After the fluid injection process is completed, the formation may have portions that have lower amounts of hydrocarbons produced (more hydrocarbons remaining) than other parts of the formation. These effects become more and more pronounced as the distance between the injection and production locations increases.

The ability to inject and/or produce from multiple places in a single wellbore allows a decrease in the distance between injection and production locations and an increase in the rate of injection and production, as compared to conventional two wellbore processes and/or wellbores that allow injection at the end of the wellbore and production from the opposite end of the wellbore. Multiple injection and production locations along the length of a single wellbore allow selective injection of fluids into the hydrocarbon layer and selective production of formation fluids from the hydrocarbon layer using a single wellbore. The methods and systems described herein allow injection and production of fluids, or heating from multiple places in a single substantially horizontal, deviated wellbore, or vertical wellbore and/or fracturing of multiple sections of a hydrocarbon containing formation.

The inability to treat hydrocarbon containing formations (for example, relatively low permeability hydrocarbon containing formation) may be improved by reducing the distance between the injection and production points and increasing the contact area of the reservoir with the wellbore. Using multiple injection and production points in a single wellbore allows significant reduction in the distance between the injection and production points. Reduction in the distance between the injection and production points may reduce the time required to inject and produce fluids for any given improved recovery method. The reduction in such a distance provides efficient placement of injected fluids and, therefore, efficient displacement of hydrocarbons from the formation. The ability of the injected fluids to displace hydrocarbons enhances a contact area of the wellbore containing injection fluid with the formation. In addition, injection of fluids in such a manner provides an efficient displacement geometry (for example, a line drive). Injecting and producing using a single wellbore also improves fluid drainage and injection as compared to using an injection wellbore and a production wellbore.

In certain embodiments, subterranean hydrocarbon containing formations are treated using a single wellbore for injection of fluid and production of formation fluids. By simultaneously injecting fluid and producing hydrocarbons using selective injection and production sections in a single wellbore the distance between the injection and production portions in the reservoir is reduced, and contact area of the hydrocarbon containing formation with the wellbore is increased, as compared to conventional two wellbore production methods. Thus, displacement (for example, mobilization) of hydrocarbons is enhanced, and more hydrocarbons are produced per area of hydrocarbon layer. Simultaneously injecting fluid and producing hydrocarbons from a single wellbore may allow production from hydrocarbon layers that are deemed uneconomical to produce using conventional chemical or steam flooding methods. For example, hydrocarbons may be produced from a 20 to 40 acre reservoir, with a conventional five spot well pattern, using chemical or steam flooding through wellbores that include crossover packers or other embodiments that allow selective injection and production sections.

The methods and systems described herein allow selective control (for example, location and rates) of injection and production, from each location along the wellbore using, for example, sliding sleeves. For example, if a certain production location is producing mostly water it may be possible in some embodiments to shut-in (close) this production location. Similarly, if injection of fluids is no into a certain location of the hydrocarbon layer, that location of the wellbore may be shut off (closed) and the fluid will automatically be redirected to another location of the wellbore and ultimately into the hydrocarbon layer.

In some embodiments, a flow control device may be used to allow for independent control of injection and/or production rates at injection and/or production locations in the well. In some embodiments, different rates of injection and/or production are desired at different locations along the length of the wellbore. A flow control device, such as, but not limited to, sliding sleeves, may be used to control rates of production and/or injection. In some embodiments, flow control devices may control rates of production and/or injection by limiting production and/or injection at one location along the length of the wellbore while allowing for greater flow at another location along the length of the wellbore. The flow control device may allow for different production and/or injection rates at various production and/or injection locations in the single wellbore.

In some embodiments, use of a single wellbore for injecting and producing fluids enhances hydrocarbon recovery processes such as water flooding, enhanced oil recovery (chemical flooding, CO2flooding, steam flooding etc.).

In some embodiments, injection of fluid into a hydrocarbon containing section currently being produced and/or a hydrocarbon section after production. In some embodiments, production of fluids is performed from a treated section (for example, a section treated with injection fluid) or a section undergoing treatment (for example, a section being treated with injection fluids). For example, production from sections of the hydrocarbon containing formation may be performed by allowing injection fluids to flow through hydrocarbon section being produced. In another example, injection of fluids into a section of the hydrocarbon containing formation may be ceased and production of the formation fluids from the treated section is started.

In some embodiments, the single wellbore for injecting and producing fluids may be used for only injection or only production. The single wellbore described herein for production may be used to inject the fluids into the subterranean hydrocarbon containing formation, thus allowing only injection. Similarly, a single wellbore described herein for injection may be used to produce the fluids from the subterranean hydrocarbon containing formation, thus allowing only production.

In some embodiments, a multiple injection and production wellbore is used to stimulate a well and/or create fractures. For example, acidizing a well, well stimulation acidizing, and/or hydraulic fracturing of a well. The use of an injection and producing wellbore may reduce fracturing times by placing two or more fractures simultaneously. For example, fluid injected into a section of a hydrocarbon containing formation may be pressurized. The pressurized fluid enters the formation and may create fractures in at least two portions of the hydrocarbon containing formation at the same time.

Use of a single wellbore may improve the amount of hydrocarbons recovered from the hydrocarbon containing formation as compared to conventional methods. For example, at least about 15%, at least about 30%, at least about 55%, or at least about 90% more hydrocarbons may be recovered from the formation as compared to a water flood or steam drive process using a two wellbore system. In some embodiments, the fluids produced from the formation are mobilized fluids. Producing mobilized fluids may also increase the total amount of hydrocarbons produced from oil shales, tar sands and oil sands.

The produced mixture may have assessable properties (for example, measurable properties). The produced mixture properties are determined by operating conditions in the formation being treated (for example, temperature, and/or pressure in the formation). In certain embodiments, the operating conditions may be selected, varied, and/or maintained to produce desirable properties in hydrocarbons in the produced mixture. For example, the produced mixture may include hydrocarbons that have properties that allow the mixture to be easily transported (for example, sent through a pipeline without adding diluent or blending the mixture and/or resulting hydrocarbons with another fluid). For example, the use of steam injection for heavy oil production in a multi-point production and injection system will result in the produced fluids being maintained at a high temperature while they are being produced from the wellbore. This provides an advantage since the fluid viscosity, which is very temperature dependent, will remain low during production all the way to the surface.

In some embodiments, a system for treating a subterranean hydrocarbon containing formation includes a substantially horizontal wellbore, and one or more packers (crossover tool) positioned in the wellbore. At least one of the packers allows injection of fluid in a subterranean hydrocarbon containing formation while allowing fluid to be produced through the packer or another portion of the wellbore to the surface of the hydrocarbon containing formation. Use of the packer or set of packers described herein provides an alternative flow path in the wellbore, but separated from the injection/production fluid flow path.

In some embodiments, a section of hydrocarbon containing layer between two packers includes multiple fractures or injection/production points. The injected fluid may, in some embodiments, be heated. The packer may allow, during use, fluid communication between a portion of central tubing in the substantially horizontal wellbore and a portion of an annulus of the substantially horizontal wellbore. In some embodiments, the packer (crossover tool) allows, during use, fluid communication between a first portion of an annulus of the substantially horizontal wellbore and a first portion of central tubing in the substantially horizontal wellbore while allowing fluid communication between a second portion of the central tubing in the substantially horizontal wellbore and a second portion of the annulus of the substantially horizontal wellbore. Sections of the wellbore separated by packers may have one or flow pathways that allow fluid to flow towards the wellbore (for example, multiple fractures or injection/production pathways).

In some embodiments, the fluids injected and/or produced through an injection/production wellbore exchanges heat. Exchange of heat allows the injected fluid remains hot and the produced fluid remains hot, and thus less heat loss to the hydrocarbon containing layer is observed. The use of multiple packers in combination with multiple injection and production points in the wellbore may allow sufficient heat to be exchanged to inhibit precipitation or solidification of paraffins in the mobilized hydrocarbons. Thus, wellbore heaters may not be required or externally heating of the wellbore may not be required.

FIG. 1depicts an embodiment for treating a formation using an injection/production wellbore system.FIG. 2depicts a side view of an embodiment of fluid flow through a crossover packer.FIG. 3depicts a side view of packers104A/104C.FIG. 4depicts a side view of packer104B.FIG. 5depicts a cut-away side view of an embodiment of fluid flow through crossover packer104B.

As shown inFIG. 1, injection/production system100may include injection/production wellbore102and one or more packers104. Substantially horizontal injection/production wellbore102may be located in hydrocarbon containing layer106. Hydrocarbon containing layer106may be below overburden108. Portions of wellbore102may be cased and/or uncased. Wellbore102may be obtained using conventional horizontal drilling methods. In some embodiments, wellbore102is placed in a hydrocarbon containing layer106that contains fractures. The fractures may be naturally occurring or may be produced using conventional fracturing methods (for example, hydraulic fracturing, acidizing fracturing, proppants, or the like).

Injection/production wellbore102may be used to inject fluid (for example, heated water, steam, chemicals, inorganic acids, organic acids, slurries, emulsions and the like) into hydrocarbon containing layer106. Packers104A,104B,104C,104D, are spaced in the substantially horizontal portion injection/production wellbore102and are horizontally displaced from each other. In some embodiments, the packers are vertically displaced from each other. Packers104(crossover tool) may be made of any material suitable for use in an injection and/or production wellbore. In some embodiments, only packer104A is used. In other embodiments, a number of packers ranges from 1 to about 10 or greater. It should be understood that the number of packers is only limited by the length and/or spacing in the wellbore. The packers, such as104A,104B,104C,104D may be different in construction and may be organized and arranged in a different order.

Central tubing110is in fluid communication with packers104and connects with an injection source at the surface of the formation. Central tubing110and the outer walls of wellbore102form annulus112. Injection fluid may be injected in central tubing110, flow through packers104, and then out into the hydrocarbon layer through perforations114as shown by arrows116. Injection fluid may mobilize formation fluid in the hydrocarbon layer. Perforations114may include covers that open and/or close as needed to control injection and production rated and locations. For example, sliding sleeves may cover perforations114and opened and/or closed along the length of the wellbore using one or more controllers.

As shown in andFIG. 3, injection fluid flows through central tubing110into opening118of packers104A,104C. Opening118allows fluid communication between wellbore central tubing110and injection tubing string120of packer104as shown inFIG. 2. Injection tubing string120in packers104A,104C may diverge and form two injection tubing strings120′,120″. In some embodiments, injection tubing string120may diverge into at least 3 injection tubing strings, at least 6 injection tubing strings, at least 10 injection tubing strings or more. As shown inFIG. 2, as fluid flows through injection tubing string120into injection tubing strings120′,120″, the injection fluid and exits packers104A,104C through openings122into annulus112of the wellbore. The use of the divergent tubing strings allows the fluid to “crossover” from the central tubing of the wellbore to the annulus of the wellbore. A portion of the injection fluid may exit wellbore through perforations114as shown by arrows116.

A portion of the injection fluid that exits from the outlet122of packer104A flows along annulus112and enters packer104B through openings124as shown inFIG. 4. In packer104B, openings124allow fluid communication between annulus112and injection tubing strings120′,120″. Injection tubing strings120′,120″ may converge to single injection tubing string120in packer104B. As injection fluid flows through packer104B, the injection fluid converges into tubing string120and exits the packer through opening126. Such convergence of the flow of injection fluid allows the injection fluid to crossover from annulus112to central tubing110in wellbore102. The process continues along the length of the wellbore through packer104C to the end of the wellbore.

Wellbore102may include end packer104D (shown inFIG. 1). End packer104D may serve as a stop in the wellbore, and/or the annulus, and/or one or more tubing strings. End packer104D directs flow of injection fluid through perforations114and includes openings that allow mobilized hydrocarbons to flow into the wellbore from the hydrocarbon containing formation. In some embodiments, opening126of end packer104D include covers that may be removed to allow injection fluid to flow through the packer and extend the injection process into the subterranean formation.

Contact of the injection fluid with hydrocarbons in the portion of the hydrocarbon layer may reduce the viscosity of the hydrocarbons such that the hydrocarbons in the hydrocarbon section are mobilized. Reduction of hydrocarbon viscosity may occur by heating the hydrocarbon containing formation with heated injection fluid and/or treating the hydrocarbons in the hydrocarbon layer such as with the solvent in the injection fluid. In some embodiments, the injection fluid may be pressurized to a level that hydrocarbons are driven into wellbore102through perforations114′.

Mobilized hydrocarbons (for example, production fluids) may flow through end packer104D into central tubing110, and then enter packers104C,104B,104A as shown by arrows130inFIG. 1. In some embodiments, heat from injection fluid may heat mobilized hydrocarbons to enhance flow through packers104to the surface of the formation. A portion of the hydrocarbons may enter annulus112through perforations114′.

Mobilized hydrocarbons enter packer104C through opening132of production tubing134(see, for example,FIGS. 2 and 3). Production tubing string134is in fluid communication with wellbore central tubing110. Central tubing110may be in fluid communication with end packer104D. In packers104A and104C, production tubing string134diverges into at least two production tubing strings134′,134″. In some embodiments, production tubing string diverges into at least 3 production tubing strings, at least 6 production tubing strings, at least 10 production tubing or more production tubing strings or annuli. Mobilized hydrocarbons flow through production tubing134production tubing strings134′,134″ and exits packers104C,104A, through openings136, as shown inFIG. 3. Openings136are in fluid communication with wellbore annulus112. Flow of mobilized hydrocarbons through divergent production tubing strings allows the mobilized hydrocarbons to “crossover” between central tubing110and annulus112. Mobilized hydrocarbons flow through annulus112and enter packer104B from packer104C through opening138. Additional mobilized hydrocarbons may also enter wellbore annulus112through perforations114′ and flow into packer104B.

In some embodiments, while fluids are being produced through packer104C, fluids are being injected into the hydrocarbon layer through the packer as described herein. In packer104B (see, for example,FIG. 5), production tubing strings134′,134″ converge into production tubing string134while injection tubing strings120′,120″ converge to single injection tubing string120. Such convergence allows mobilized hydrocarbons crossover from wellbore annulus112to wellbore central tubing110and injection fluids to crossover from wellbore annulus112to central tubing110in an opposite direction.

Mobilized hydrocarbons exit packer104B through opening140and enter packer104A through opening132(see,FIG. 3). In packer104A, the mobilized hydrocarbons crossover from central tubing110to annulus112. The process continues through packers104until mobilized hydrocarbons reach the surface. Conventional methods, for example, gas lift and/or pressure, may be used to move hydrocarbons through wellbore102.

In some embodiments, the packers allow crossover of fluid from an annulus to the central tubing using a single entry opening and single exit opening.FIG. 6depicts a cut away side view of wellbore102that includes an embodiment of a crossover packer having single entry and exit openings.FIG. 7depicts a side view of an embodiment crossover packer140. Crossover packer140includes arcuate (curved) tubing142and arcuate tubing144. Arcuate tubing142may be vertically/horizontally displaced from arcuate tubing144. Arcuate tubing142allows injection fluid from annulus112to enter packer140through opening146, crossover, and exit the packer through opening148into central tubing110of the wellbore. Arcuate tubing144allows mobilized hydrocarbons to enter packer140through opening150(that communicates with central tubing of wellbore102), crossover, and exit the packer through opening152(that communicates with annulus112of the wellbore).

In some embodiments, injection tubing142and production tubing144is substantially horizontal and vertically displaced from each other as shown inFIG. 8. Such displacement is advantageous when two or more tubing strings run throughout the horizontal section of the wellbore. As shown inFIG. 9, packers140may be positioned in a single wellbore. The wellbore may include perforations that include coverings that allow the perforations to be selectively opened and closed. One or more controllers (for example, a computer) may control the coverings. Fluid may flow through injection tubing142(shown inFIG. 8) of packers140A,140B,140C, and140D. The fluid may exit the wellbore through perforations114between packers140A and140B and/or perforations114between packers140C and140D and contact sections of hydrocarbon layer hydrocarbon layer106adjacent to the perforations. Mobilized fluids flow into annulus112through perforations114′ and enter production tubing144(shown inFIG. 8) of packers140B and140D.

In some embodiments, perforations114,114′ may be covered. The covering may be remotely controlled from the surface (for example, connected to a computer controller) to open and close such that injection and/or production may be alternated along the length of the wellbore and/or the coverings may be partially closed or opened to control flow rate. For example, perforations114between packers140C and140D and/or perforations114′ after packer140D may be open while perforations114between140A and140B and/or perforation114′ between140B and140C are closed and vise versa. In some embodiments, injection and production is performed simultaneously along the length of the wellbore.

In some embodiments, production and/or injection tubing strings of packers104,140connect to tubing strings of one or more additional packers142and/or104or other packers in wellbore102. Flowing fluid through tubing strings may inhibit reactions of injected fluids with production fluids in the wellbore.

In some embodiments, injection and production of fluid using the system described is performed in a fractured hydrocarbon layer.FIG. 10depicts a schematic of an embodiment of the injection and production from a single wellbore in a fractured hydrocarbon layer. Injection of fluid into section154of hydrocarbon containing layer106containing fractures156through injection/production wellbore102containing packers104. In some embodiments, packers140and/or a combination of packers104and140are used in the single wellbore.

As shown, injected fluid moves formation fluids in section154A in a linear direction (line drive) as shown by arrow116. Formation fluids may be produced from section158B of hydrocarbon containing layer106using injection/production wellbore102. Injection fluid flow through wellbore102and enters hydrocarbon section154B drives formation fluids into section158B as shown by arrows130. The formation fluids may be produced from hydrocarbon section158B using wellbore102. Packers104allow selective injection into section154A,154B and/or production from sections158A,158B. In some embodiments, packers140and/or a combination of packers104and140are positioned in wellbore102. Use of multiple points of injection and production where each point of injection and production is a fracture may improve the displacement geometry in the hydrocarbon layer. Improvement in the displacement geometry improves the hydrocarbon displacement and sweep efficiency as compared to conventional five spot or nine-spot injector-producer pattern. An improvement in sweep efficiency leads to improvements in hydrocarbon recovery.

It should be understood that the direction of all the arrows in the Figures may be reversed leading a reversal in roles of all the injection and production zones. Thus, in this embodiment, the central tubing will not be connected to an injection source at the surface but will be used to transport the produced hydrocarbons to the surface. The annulus region between the central tubing and the wellbore,112may carry the injection fluid from the surface to the sub-surface. Thus, arrows130represent the injection fluid and arrows116would represent the produced fluid. The zones where injection occurs into the formation will now become zones where production occurs from the formation and vice versa.

As shown inFIGS. 1-10, multiple injection and production points in a single wellbore have numerous advantages. In some embodiments, an increased sweep of hydrocarbons in the case of alternate injection and production zones and more efficient reservoir drainage may occur. Multiple injection and production points in a single wellbore also leads to a reduction in the time taken to perform fracturing treatments in a wellbore. For example, instead of using the conventional treatment technique of creating one fracture at a time, the injection tubing and the production tubing as to inject fracturing fluid into the formation and create two or more fractures simultaneously in the same wellbore. Thus, reduction in the time needed to create the same number fractures is observed.

Multiple injection and production points in a single wellbore may also be used in conjunction with downhole flow control devices (such as sliding sleeves) to selectively access different injection and production points in the formation. Selective arrangement of multiple packers as described herein and/or fracturing from a single wellbore as described herein may more efficiently create multiple fractures in the wellbore as compared to using the more common plug-and-perforate or ball drop techniques. Access of different injection and production points in the formation may provide a way to implement a particular fracturing sequence. For example, it could be used to increase fracture complexity in a reservoir by using “alternate fracturing”. Fractures may created in a 1-3-2-5-4 sequence, where the numbers refer to the location of the fractures starting at the toe. Greater fracture complexity may be achieved in the even numbered fractures. Using the systems and methods describe herein, which uses separate channels of injection and production in the wellbore, and using downhole flow control devices to selectively control the opening and closing of the fluid injection and production ports, one could possibly use the production tubing in the wellbore as injection tubing and create fractures in alternate zones. Time spent in moving the tubing to specific locations may be saved as the down-hole flow control devices are selectively opened and closed to control the locations and sequence of fracturing. Similarly, multiple injection and production points may be used to efficiently fracture the formation in any other customized sequence or order.

In certain embodiments, formation conditions (for example, pressure, and temperature) and/or fluid production are controlled to produce fluids with selected properties. For example, formation conditions and/or fluid production may be controlled to produce fluids with a selected API gravity and/or a selected viscosity. The selected API gravity and/or selected viscosity may be produced by combining fluids produced at different formation conditions (for example, combining fluids produced at different temperatures during an in situ hybrid treatment). In certain embodiments, a mixture is produced from the injection/production well. The produced hydrocarbons may be transportable through a pipeline without adding diluent or blending the mixture with another fluid.

It is to be understood the invention is not limited to particular systems described which may, of course, vary. It is also to be understood that the terminology used herein is for the purpose of describing particular embodiments only, and is not intended to be limiting. As used in this specification, the singular forms “a”, “an” and “the” include plural referents unless the content clearly indicates otherwise. Thus, for example, reference to “a core” includes a combination of two or more cores and reference to “a material” includes mixtures of materials.