Patent Application
20150218886
The present techniques relate to increasing flow from a subterranean formation. Specifically, techniques are disclosed for drilling small lateral holes out from a central wellbore to enhance the flow to the central wellbore.
This section is intended to introduce various aspects of the art that may be topically associated with embodiments of the present techniques. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present techniques. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
As conventional hydrocarbon reservoirs (e.g., high-permeability onshore reservoirs, high-permeability reservoirs located in shallow ocean water, etc.), are depleted other hydrocarbon sources must be developed to keep up with energy demands. Such reservoirs may include any number of unconventional hydrocarbon reservoirs, such as heavy oil reservoirs, deep-water oil reservoirs, and natural gas reservoirs.
One such unconventional hydrocarbon resource is natural gas produced from formations that form unconventional gas reservoirs, including, for example, shale reservoirs and coal seams. Because unconventional gas reservoirs may have insufficient permeability to allow significant fluid flow to a wellbore, many of such unconventional gas reservoirs are currently not considered as economically attractive sources of natural gas. However, natural gas has been produced for years from low permeability reservoirs having natural fractures. Furthermore, a significant increase in shale gas production has resulted from hydraulic fracturing, which can be used to create extensive artificial fractures around wellbores. When combined with horizontal drilling, which is becoming more commonly used in industry, the hydraulic fracturing may allow formerly unattractive reservoirs to become commercially viable.
Currently, many shale gas, tight gas, and tight oil formations are hydraulically fractured using a combination of water, proppant, and chemicals to create higher connectivity in the formation and enhance both recovery rates and cumulative volumes produced from a single horizontal wellbore. This method has proven to be economically viable, but has encountered some opposition. Some of the concerns involve the release of chemicals into the subsurface, the large quantities of water utilized in the process, and the noise and truck traffic associated with the process.
The industry is also concerned with several aspects of hydraulic fracturing, including the volumes of water, and the costs. The volumes of water used in hydraulic fracturing are often very large, and may exceed several million barrels of water per fracture job. In many locations in the United States, water is quite scarce, so water sourcing can be an issue. In addition, a substantial fraction of the injected water, for example, between 10-50%, can be produced back and may require treatment. Transport, treatment, and disposal of this water can be quite costly, for example, in excess of $10/bbl in parts of the northeastern United States. Moreover, a typical hydraulic fracturing process can require 10 or more stages with each stage costing $100,000-$300,000.
As a result of some of these issues, some governmental entities are proposing bans on hydraulic fracturing, jeopardizing the access to the resources. Technologies that can provide access to shale gas resources without the use of hydraulic fracturing may become the preferred means of production enhancement in these formations by many government bodies.
Several patents and pieces of literature discuss creating lateral wells to increase production from reservoirs without fracturing. For example, U.S. Pat. No. 5,533,573 discusses a method for completing multi-lateral wells and maintaining selective re-entry into laterals. A first lateral well is drilled from a primary well bore and a string of external casing packers and a packer bore receptacle are run therein. Once the orientation of the packer bore receptacle is determined, an orientation anchor of a retrievable whipstock assembly is mounted thereto. Thereafter, a second lateral well may be drilled. Once the second lateral well is drilled, the whipstock assembly may be retrieved and replaced with a scoophead diverter assembly which also includes an orientation anchor for mating with the packer bore receptacle. At this time, a string of external casing packers may be run into the second lateral well through the scoophead diverter assembly. Finally, a selective re-entry tool is run into the scoophead assembly. The selective re-entry tool includes a diversion flapper for selecting either the first or second lateral well bore. Selective re-entry is desirable for the purpose of performing well intervention techniques. The re-entry tool may be actuated by a device located on a coil tubing work string which may be operated from the surface.
U.S. Patent Application No. 2011/0017445 discloses a method and device for making lateral openings out of a wellbore in a well formation. In a disclosed method, fluid is flowed through a motherbore tubular, such as a completion or production pipe, and then through a needle pipe that is aimed at the formation. The needle pipe, which includes at least one pipe section, is positioned inside or outside a motherbore tubular and the pipe section is positioned to be telescopically displaceable with regard to another pipe.
U.S. Pat. No. 4,497,381 discusses an earth well drilling apparatus, which uses a hydraulic jet drilling head and hydraulic pressure to bend a pipe and drill laterally into a formation. The drilling apparatus includes piping in a well, a metal drilling tube within the piping, and a hydraulic jet drilling head secured to the lower end of the tube. A seal is disposed between the piping and the tube. The drilling head is pushed downwards through the piping, under hydraulic pressure, and through a tube bending assembly. The tube bending assembly is laterally extensible from a retracted position substantially within the structure. The tube bending assembly bends the metal drilling tube, directing the drilling head laterally toward the formation.
These references disclose the formation of laterals drilled from a central wellbore. However, none of the reference discussed above disclose drilling a number of holes from a primary wellbore using a plurality of hydraulically-powered drill bits.
An embodiment described herein provides an apparatus for penetrating a subsurface formation. The apparatus includes a hollow member with an inner and outer annulus. A flexible hose is disposed in the outer annulus and attached to the inner annulus, wherein the flexible hose is configured to convey a fluid from the inner annulus to a drilling apparatus. The drilling apparatus is configured to penetrate the outer annulus and the subsurface formation, and to pull the flexible hose into the formation as the drilling apparatus penetrates the subsurface formation.
Another embodiment provides a method of creating a high flow network in subterranean formation. The method includes placing a drilling assembly including a flexible hose and a drilling apparatus into a wellbore, wherein the flexible hose is configured to convey a fluid to the drilling apparatus. A fluid is injected into the flexible hose, wherein the fluid flow through the flexible hose drives the drilling apparatus to penetrate through the subterranean formation and pull the associated flexible hoses into the formation.
Another embodiment provides a method of harvesting hydrocarbons from a subterranean formation. The method includes creating a high flow network in the subterranean formation by drilling a small lateral well from a main well. The small lateral is drilled by placing a tubular including a fluid-conveying hollow line, into a wellbore, wherein the fluid-conveying hollow line is in fluid communication with a drilling apparatus through a flexible hose. A fluid is injected through the fluid-conveying hollow line into the flexible hose, wherein the fluid forces the drilling apparatus to penetrate the subterranean formation and pull the flexible hose into the formation behind the drilling apparatus. Hydrocarbons are produced from the subterranean formation.
The advantages of the present techniques are better understood by referring to the following detailed description and the attached drawings, in which:
In the following detailed description section, the specific embodiments of the present techniques are described in connection with exemplary embodiments. However, to the extent that the following description is specific to a particular embodiment or a particular use of the present techniques, this is intended to be for exemplary purposes only and simply provides a description of the exemplary embodiments. Accordingly, the present techniques are not limited to the specific embodiments described below, but rather, such techniques include all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims.
At the outset, and for ease of reference, certain terms used in this application and their meanings as used in this context are set forth. To the extent a term used herein is not defined below, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent. Further, the present techniques are not limited by the usage of the terms shown below, as all equivalents, synonyms, new developments, and terms or techniques that serve the same or a similar purpose are considered to be within the scope of the present claims.
“Cleat system” is the system of naturally occurring joints that are created as a coal seam forms over geologic time. A cleat system allows for the production of natural gas if the provided flow to the coal seam is sufficient.
“Coal” is a solid hydrocarbon, including, but not limited to, lignite, sub-bituminous, bituminous, anthracite, peat, and the like. The coal may be of any grade or rank. This can include, but is not limited to, low grade, high sulfur coal that is not suitable for use in coal-fired power generators due to the production of emissions having high sulfur content.
“Coalbed methane” (CBM) is a natural gas that is adsorbed onto the surface of coal. CBM may be substantially comprised of methane, but may also include ethane, propane, and other hydrocarbons. Further, CBM may include some amount of other gases, such as carbon dioxide (CO2) and nitrogen (N2).
“Directional drilling” is the intentional deviation of the wellbore from the path it would naturally take. In other words, directional drilling is the steering of the drill string so that it travels in a desired direction. Directional drilling can be used for increasing the drainage of a particular well, for example, by forming deviated branch bores from a primary borehole. Directional drilling is also useful in the marine environment where a single offshore production platform can reach several hydrocarbon bearing subterranean formations or reservoirs by utilizing a plurality of deviated wells that can extend in any direction from the drilling platform. Directional drilling also enables horizontal drilling through a reservoir to form a horizontal wellbore. As used herein, “horizontal wellbore” represents the portion of a wellbore in a subterranean zone to be completed which is substantially horizontal or at an angle from vertical in the range of from about 45° to about 135°. A horizontal wellbore may have a longer section of the wellbore traversing the payzone of a reservoir, thereby permitting increases in the production rate from the well.
A “facility” is tangible piece of physical equipment, or group of equipment units, through which hydrocarbon fluids are either produced from a reservoir or injected into a reservoir. In its broadest sense, the term facility is applied to any equipment that may be present along the flow path between a reservoir and its delivery outlets, which are the locations at which hydrocarbon fluids either leave the model (produced fluids) or enter the model (injected fluids). Facilities may comprise production wells, injection wells, well tubulars, wellhead equipment, gathering lines, manifolds, pumps, compressors, separators, surface flow lines, and delivery outlets. In some instances, the term “surface facility” is used to distinguish those facilities other than wells.
“Formation” refers to a body or section of geologic strata, structure, formation, or other subsurface solids or collected material that is sufficiently distinctive and continuous with respect to other geologic strata or other characteristics that it can be mapped, for example, by seismic techniques. A formation can be a body of geologic strata of predominantly one type of rock or a combination of types of rock, or a fraction of strata having substantially common set of characteristics. A formation can contain one or more hydrocarbon-bearing subterranean formations. Note that the terms formation, hydrocarbon bearing subterranean formation, reservoir, and interval may be used interchangeably, but may generally be used to denote progressively smaller subsurface regions, zones, or volumes. More specifically, a geologic formation may generally be the largest subsurface region, a hydrocarbon reservoir or subterranean formation may generally be a region within the geologic formation and may generally be a hydrocarbon-bearing zone, a formation, reservoir, or interval having oil, gas, heavy oil, and any combination thereof. An interval or production interval may generally refer to a sub-region or portion of a reservoir. A hydrocarbon-bearing zone, or production formation, may be separated from other hydrocarbon-bearing zones by zones of lower permeability such as mudstones, shales, or shale-like (highly compacted) sands. In one or more embodiments, a hydrocarbon-bearing zone may include heavy oil in addition to sand, clay, or other porous solids.
A “fracture” is a crack, delamination, surface breakage, separation, crushing, rubblization, or other destruction within a geologic formation or fraction of formation that is not related to foliation or cleavage in metamorphic formation, along which there has been displacement or movement relative to an adjacent portion of the formation. 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.
“Fracturing” refers to the structural degradation of a treatment interval, such as a subsurface shale formation, from applied thermal or mechanical stress. Such structural degradation generally enhances the permeability of the treatment interval to fluids and increases the accessibility of the hydrocarbon component to such fluids. Fracturing may also be performed by degrading rocks in treatment intervals by chemical means. “Fracture network” refers to a field or network of interconnecting fractures, usually formed during hydraulic fracturing. A “fracture field” is a group of fractures, which may or may not be interconnected, and are created by a single fracturing event, such as by a volumetric change in a zone proximate to a target formation, which fractures the target formation.
“Hydraulic fracturing” is used to create single or branching fractures that extend from the wellbore into reservoir formations so as to stimulate the potential for production. A fracturing fluid, typically a viscous fluid, is injected into the formation with sufficient pressure to create and extend a fracture, and a proppant is used to “prop” or hold open the created fracture after the hydraulic pressure used to generate the fracture has been released. When pumping of the treatment fluid is finished, the fracture may close. The fracture may be artificially held open by injection of a proppant material.
“Hydrocarbon production” refers to any activity associated with extracting hydrocarbons from a well or other opening. Hydrocarbon production normally refers to any activity conducted in or on the well after the well is completed. Accordingly, hydrocarbon production or extraction includes not only primary hydrocarbon extraction but also secondary and tertiary production techniques, such as injection of gas or liquid for increasing drive pressure, mobilizing the hydrocarbon or treating by, for example chemicals or hydraulic fracturing the wellbore to promote increased flow, well servicing, well logging, and other well and wellbore treatments.
“Hydrocarbons” are generally defined as molecules formed primarily of carbon and hydrogen atoms such as oil and natural gas. Hydrocarbons may also include other elements, such as, but not limited to, halogens, metallic elements, nitrogen, oxygen, and/or sulfur. Hydrocarbons may be produced from hydrocarbon bearing subterranean formations through wells penetrating a hydrocarbon containing formation. Hydrocarbons derived from a hydrocarbon bearing subterranean formation may include, but are not limited to, kerogen, bitumen, pyrobitumen, asphaltenes, oils, natural gas, or combinations thereof. Hydrocarbons may be located within or adjacent to mineral matrices within the earth. Matrices may include, but are not limited to, sedimentary rock, sands, silicilytes, carbonates, diatomites, and other porous media.
As used herein, “material properties” represents any number of physical constants that reflect the behavior of a rock. Such material properties may include, for example, Young's modulus (E), Poisson's Ratio (v), tensile strength, compressive strength, shear strength, creep behavior, and other properties. The material properties may be measured by any combinations of tests, including, among others, a “Standard Test Method for Unconfined Compressive Strength of Intact Rock Core Specimens,” ASTM D 2938-95; a “Standard Test Method for Splitting Tensile Strength of Intact Rock Core Specimens [Brazilian Method],” ASTM D 3967-95a Reapproved 1992; a “Standard Test Method for Determination of the Point Load Strength Index of Rock,” ASTM D 5731-95; “Standard Practices for Preparing Rock Core Specimens and Determining Dimensional and Shape Tolerances,” ASTM D 4435-01; “Standard Test Method for Elastic Moduli of Intact Rock Core Specimens in Uniaxial Compression,” ASTM D 3148-02; “Standard Test Method for Triaxial Compressive Strength of Undrained Rock Core Specimens Without Pore Pressure Measurements,” ASTM D 2664-04; “Standard Test Method for Creep of Cylindrical Soft Rock Specimens in Uniaxial Compressions,” ASTM D 4405-84, Reapproved 1989; “Standard Test Method for Performing Laboratory Direct Shear Strength Tests of Rock Specimens Under Constant Normal Stress,” ASTM D 5607-95; “Method of Test for Direct Shear Strength of Rock Core Specimen,” U.S. Military Rock Testing Handbook, RTH-203-80, available at http://www.wes.army.mil/SL/MTC/handbook/RT/RTH/203-80.pdf (last accessed on Oct. 1, 2010); and “Standard Method of Test for Multistage Triaxial Strength of Undrained Rock Core Specimens Without Pore Pressure Measurements,” U.S. Military Rock Testing Handbook, available at http://www.wes.army.mil/SL/MTC/handbook/RT/RTH/204-80.pdf (last accessed on Jun. 25, 2010). One of ordinary skill will recognize that other methods of testing rock specimens from formations may be used to determine the physical constants used herein.
“Natural gas” refers to various compositions of raw or treated hydrocarbon gases. Raw natural gas is primarily comprised of light hydrocarbons such as methane, ethane, propane, butanes, pentanes, hexanes and impurities like benzene, but may also contain small amounts of non-hydrocarbon impurities, such as nitrogen, hydrogen sulfide, carbon dioxide, and traces of helium, carbonyl sulfide, various mercaptans, or water. Treated natural gas is primarily comprised of methane and ethane, but may also contain small percentages of heavier hydrocarbons, such as propane, butanes, and pentanes, as well as small percentages of nitrogen and carbon dioxide.
“Overburden” refers to the subsurface formation overlying the formation containing one or more hydrocarbon-bearing zones (the reservoirs). For example, overburden may include rock, shale, mudstone, or wet/tight carbonate (such as an impermeable carbonate without hydrocarbons). An overburden may include a hydrocarbon-containing layer that is relatively impermeable. In some cases, the overburden may be permeable.
“Permeability” is the capacity of a formation to transmit fluids through the interconnected pore spaces of the rock. Permeability may be measured using Darcy's Law: Q=(k ΔP A)/(μ L), where Q=flow rate (cm3/s), ΔP=pressure drop (atm) across a cylinder having a length L (cm) and a cross-sectional area A (cm2), μ=fluid viscosity (cp), and k=permeability (Darcy). The customary unit of measurement for permeability is the millidarcy. The term “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). The term “relatively low permeability” is defined, with respect to formations or portions thereof, as an average permeability of less than about 10 millidarcy. An impermeable layer generally has a permeability of less than about 0.1 millidarcy. By these definitions, shale may be considered impermeable, for example, ranging from about 0.1 millidarcy (100 microdarcy) to as low as 0.00001 millidarcy (10 nanodarcy).
“Porosity” is defined as the ratio of the volume of pore space to the total bulk volume of the material expressed in percent. Although there often is an apparent close relationship between porosity and permeability, because a highly porous formation may be highly permeable, there is no real relationship between the two; a formation with a high percentage of porosity may be very impermeable because of a lack of communication between the individual pores, capillary size of the pore space or the morphology of structures constituting the pore space. For example, the diatomite in one exemplary rock type found in formations, Belridge, has very high porosity, at about 60%, but the permeability is very low, for example, less than about 0.1 millidarcy.
“Pressure” refers to a force acting on a unit area. Pressure is usually shown as pounds per square inch (psi). “Atmospheric pressure” refers to the local pressure of the air. Local atmospheric pressure is assumed to be 14.7 psia, the standard atmospheric pressure at sea level. “Absolute pressure” (psia) refers to the sum of the atmospheric pressure plus the gauge pressure (psig). “Gauge pressure” (psig) refers to the pressure measured by a gauge, which indicates only the pressure exceeding the local atmospheric pressure (a gauge pressure of 0 psig corresponds to an absolute pressure of 14.7 psia).
As previously mentioned, a “reservoir” or “hydrocarbon reservoir” is defined as a pay zone or production interval (for example, a hydrocarbon bearing subterranean formation) that includes sandstone, limestone, chalk, coal, and some types of shale. Pay zones can vary in thickness from less than one foot (0.3048 m) to hundreds of feet (hundreds of m). The permeability of the reservoir formation provides the potential for production.
“Shale” is a fine-grained clastic sedimentary rock that may be found in formations, and may often have a mean grain size of less than 0.0625 mm. Shale typically includes laminated and fissile siltstones and claystones. These materials may be formed from clays, quartz, and other minerals that are found in fine-grained rocks. Non-limiting examples of shales include Barnett, Fayetteville, and Woodford in North America. Shale has low matrix permeability, so gas production in commercial quantities requires fractures to provide flow. Shale gas reservoirs may be hydraulically fractured to create extensive artificial fracture networks around wellbores. Horizontal drilling is often used with shale gas wells.
“Substantial” when used in reference to a quantity or amount of a material, or a specific characteristic thereof, refers to an amount that is sufficient to provide an effect that the material or characteristic was intended to provide. The exact degree of deviation allowable may in some cases depend on the specific context.
“Thermal fractures” are fractures created in a formation caused by expansion or contraction of a portion of the formation or fluids within the formation. The expansion or contraction may be caused by changing the temperature of the formation or fluids within the formation. The change in temperature may change the pressure of fluids within the formation, resulting in the fracturing. Thermal fractures may propagate into or form in neighboring regions significantly cooler than the heated zone.
“Tight oil” is used to reference formations with relatively low matrix permeability, porosity, or both, where liquid hydrocarbon production potential exists. In these formations, liquid hydrocarbon production may also include natural gas condensate.
“Underburden” refers to the subsurface formation below or farther downhole than a formation containing one or more hydrocarbon-bearing zones, e.g., a hydrocarbon reservoir. For example, underburden may include rock, shale, mudstone, or a wet/tight carbonate, such as an impermeable carbonate without hydrocarbons. An underburden may include a hydrocarbon-containing layer that is relatively impermeable. In some cases, the underburden may be permeable. The underburden may be a formation that is distinct from the hydrocarbon bearing formation or may be a selected fraction within a common formation shared between the underburden portion and the hydrocarbon bearing portion. Intermediate layers may also reside between the underburden layer and the hydrocarbon bearing zone.
The techniques described herein provide methods and systems for penetrating a subsurface formation with a number of lateral wells to create a highly connected network. This network can be used within low permeability formations to enhance hydrocarbon production without the use of fracturing. An exemplary method involves drilling a number of small lateral holes into a formation from a primary wellbore. The number of small lateral holes drilled can be in excess of 2, 10, 50, or 100. The average spacing can be determined by the desired increase in productivity, and may include, for example, a lateral hole every 5 meters, every 10 meters, every 20 meters, or more. In formations having large numbers natural fractures, wider spacing may be selected, while in formations having few natural fractures, narrower spacing may be desirable. The diameter of the lateral holes can be about 10 cm, 5 cm, 1 cm, or even less. The lateral holes can extend from the primary wellbore 5 m, 10 m, 50 m, 100 m, or even farther.
The techniques may be used with any type of hydrocarbon bearing subterranean formation, such as a shale gas formation, a tight oil formation, a coalbed, or any number of other types of formations. Any types of hydrocarbons may be harvested using the techniques described, including oil, gas, or mixed hydrocarbons. Further, the techniques may be used to penetrate other types of formations, such as formations used for the production of geothermal energy. In one embodiment, the techniques can be used to enhance production of natural gas from unconventional reservoirs (e.g., low permeability gas reservoirs, such as shale or coal). In another embodiment, the techniques can be used to enhance oil production from tight carbonate reservoirs. The techniques are not limited to these examples, as they may be used to create small lateral holes in any number of other formations.
Generally, the small lateral holes are drilled from the central wellbore by a hydraulically powered, and propelled, drill bit. The drill bit is attached to a flexible hose that may be coiled in an outer annulus in the wellbore, and is pulled into the formation by the hydraulically powered drill bit. The end of the flexible hose opposite the drill bit can be fluidically coupled to an inner annulus within the wellbore, which may be used to provide the fluid to power the drill bit. Once the drilling is completed, the flexible hose may be left in the small lateral hole. The hose may be configured to be degraded or dissolved to increase the production from the small lateral hole.
Further, the well may be placed at the top of the formation and utilize penetration rates to enable gravity to cause the tubes to bend downward as they penetrate the formation. This can allow for wider access of a formation from a single well.
In contrast, the techniques disclosed herein form a series of small lateral holes outward from a central wellbore. For example, a well 102 may be drilled through an overburden 104 to a hydrocarbon bearing subterranean formation 106. Although the well 102 may penetrate through the hydrocarbon bearing subterranean formation 106 and into the underburden 108, small lateral wellbores 110 can be drilled from the well 102 into hydrocarbon bearing subterranean formation 106. The small lateral wellbores 110 may turn downward into the hydrocarbon bearing subterranean formation 106 under the force of gravity, crossing numerous bedding planes 112, and potentially intersecting natural fractures.
As described in more detail with respect to the following figures, each of the small lateral wellbores 110 can be drilled by a drilling apparatus, such as a hydraulically powered drill bit, coupled to the end of a flexible hose. The flexible hose can be coiled in an outer annulus of the well 102 for placement into the well. An inner annulus of the well 102 can carry fluid to each flexible hose, which, in turn, carries the fluid to the drilling apparatus. As the drilling apparatus penetrates the formation, the flexible hose is pulled along behind it. The small lateral wellbores 110 can be staged to increase the pressure available for drilling. For example, ball seals may be dropped and retrieved to allow subsets of the small lateral wells 110 to be drilled in sequence.
Similar to a hydraulic fracturing process, the drilling of the small lateral wells 110 may utilize an extensive amount of equipment at the well site. This equipment may include fluid storage tanks 112 to hold the hydraulic fluid, and blenders 114 to blend the hydraulic fluid with other materials, such as drilling particles 116, acid, and other chemical additives, forming the final hydraulic fluid mixture. The hydraulic fluid may be pressurized and may be at a pressure above the pressure in at least some point in the reservoir pressure. The hydraulic fluid can include water, CO2, N2, hydrocarbons, inert or semi-inert fluids, or any combinations thereof. The fluid may also comprise fine solids with a median effective diameter of the solids of less than 1 mm, less than 50 μm, or less where the effective diameter may be determined by taking the square root of the quantity of the largest cross-sectional area of a solid multiplied by four and divided by pi.
The low pressure slurry 118 may be run through a treater manifold 120, which may use pumps 122 to adjust flow rates, pressures, and the like, creating a high pressure hydraulic fluid 124, which can be pumped down the well 102 to power the drilling assemblies that penetrate the hydrocarbon bearing subterranean formation 106. A mobile command center 126 may be used to control the drilling process.
In one embodiment, the goal of the multi-lateral stimulation is to create a highly-conductive flow zone 128 by intersecting the small lateral wells 110 with natural fractures and hydrocarbon containing pockets in the hydrocarbon bearing subterranean formation 106. In another embodiment the goal of the multi-lateral stimulation is to create a highly-conductive flow zone 128 by increasing the effective contact area of the well 102 and small lateral wells 110 with the subterranean formation 106. Analogous to a fracture zone or cloud in hydraulic fracturing, the highly-conductive flow zone 128 may be considered a network of flow channels generally radiating out from the well 102.
After the drilling process 100 is completed, the hydraulic fluids are flowed back to minimize formation damage. For example, contact with the hydraulic fluids may result in imbibement of the fluids by pores in the hydrocarbon bearing subterranean formation 106, which can lower the productivity of the reservoir. The fluids may also be flushed to remove the materials, for example, with a solvent, acid, or other material that can dissolve or break down residual traces of the hydraulic fluids. Further, another treatment may be used to dissolve the flexible hoses, leaving open flow channels back to the well 102.
The well 102 is not limited to a vertical orientation. In various embodiments, the orientation may be vertical, horizontal, or at any other appropriate angle, for example, to follow the reservoir interval.
A flexible hose 408 is coiled within the outer annulus 404, and is fluidically coupled to the inner annulus 406 through a coupling 410 and to a hydraulically-powered drilling apparatus 412. The flexible hose 408 has a smaller diameter than the hole created by the hydraulically-powered drilling apparatus 412 to allow the flexible hose 408 to be pulled into the formation by the hydraulically-powered drilling apparatus 412. The flexible hose 408 can be selected to withstand differential pressures in excess of 500 psi, 5000 psi, 10,000 psi or more. Further, the flexible hose 408 may be abrasion resistant to withstand forces in the lateral well. The flexible hose 408 may be made from composite materials, polyamides, polyimides, corrugated steel, PTFE, carbon fiber, or any combinations thereof, as well as any other suitable high-strength material. The high-pressure hose may also be comprised of a composite material which dissolves at high temperature or when exposed to specific injected fluid compositions. As used herein, flexible indicates that the hose may withstand a minimum static bend radius of less than 15 inches without undergoing plastic deformation or other permanent damage.
The outer casing 414 of the outer annulus 404 can have a pre-drilled hole 416 to allow the hydraulically-powered drilling apparatus 412 to exit the casing and penetrate a formation. To protect the hydraulically-powered drilling apparatus 412 before use, such as during installation, a cover 418 may be installed in each pre-drilled hole 416 over the hydraulically-powered drilling apparatus 412. The cover 418 may be a wax plug, a plastic sheet, or any other suitable protective cover.
During drilling, the inner annulus 406 carries a high-pressure fluid to the flexible hose 408, which conveys the high-pressure fluid to the hydraulically-powered drill bit 412. For long horizontal wells a high flow rate will be required, in excess of 10 bbl/day (70.3 l/hour) per hole, in excess of 100 bbl/day (700 l/hour) per hole, or in excess of 1,000 bbl/day (7000 l/hour) per hole. As previously discussed, the injected fluid may include water. The injected fluid may include primarily CO2 which has a low viscosity, yet relatively high density at the high pressure and temperatures needed for this process. The low viscosity will reduce frictional wellbore losses and enable higher injection rates, while the high density will ensure the fluid can readily achieve high pressures downhole.
Once the hydraulic fluid powers up the hydraulically-powered drilling apparatus 412, it penetrates the cover 418 and starts to penetrate the formation. As the hydraulically-powered drilling apparatus 412 penetrates into the formation the flexible hose 408 is decoiled and pulled into the formation behind the apparatus. The pre-drilled hole 416 in the casing 414 allows the outer annulus 404 to carry the drilling-fluid and rock cuttings back to the surface. The pre-drilled hole 416 in the casing 414 may also have a channel to guide the hydraulically-powered drilling apparatus 412 in the early stages of formation penetration in order to stabilize the apparatus and guide the initial penetration in the desired direction.
Once drilling is complete the flexible hose 408 and hydraulically-powered drilling apparatus 412 are abandoned in the reservoir. A sufficient flow pathway remains between the hydraulically-powered drilling apparatus 412 and the wellbore since the diameter of the drilled hole is greater than that of the flexible hose 408.
Additional systems may be added to the apparatus 400 to ensure increased reliability. For example, check valves may be used to prevent the reverse flow of materials through the flexible hose 408. As another example, a check valve may be used to block flow from entering the flexible hose 408, which may be desirable in the case of too much flow entering the hose due to failure of the flexible hose or a large difference in the rock properties along the wellbore. The check valve may be placed at the coupling 410 between the flexible hose 408 and the inner annulus 406 or may be placed after the flexible hose 408 and before the drilling apparatus 412. Further, filter screens may be used between the inner annulus 406 and the flexible hose 408 to remove particles.
An axial motion of the drill bit 506 may be created by several methods. For example, the axial motion may be created by a configuration in the bit that allows fluid to exit different channels as the bit rotates. As the channels may be oriented to direct the fluid in different directions, this changes the net effective force axially applied on the drill bit by the fluid momentum. As another example, rotating components inside the drilling apparatus 500 may cause fluid to pulsate at high frequency and at varying rates through the drill bit 506, causing the net effective force axially applied to the drill bit 506 to change. In addition to the propulsion resulting from directional fluid leak-off, gravity can be used to assist in driving the apparatus and hose into the formation.
A simulation model was built to compare gas production from a typical fracture network generated in a shale formation by hydraulic fracturing vs. that generated by the method described herein to determine if similar improvements in flow could be achieved. The models indicated that similar improvements in flow were possible, and provided guidance on the number of lateral wells needed to achieve these results, described in this invention which creates highly-connected, high-flow networks.
At block 1004, a hydraulic fluid is flowed to the flexible hoses to drill the small lateral wells. As described herein, the small lateral wells can be generated with a plurality of hydraulically-powered drill bits, which would operate to mechanically drill through the formation using rotary motion, axial motion, or a combination thereof. Generally, at least two drill bits would concurrently penetrate the formation and more than 10 drill bits may operate simultaneously, as described with respect to block 1008. The high pressure hose is pulled into the formation by both gravitational force and the force issuing from the fluid leak-off exiting small perforations near the drill bit at high-velocity. The direction of penetration of the hoses and apparatuses in the formation may be governed by both gravity and the direction of the hydraulic fluid leaving the small perforations near the drill bits. The injection of the hydraulic fluid into a flexible hose and its associated drilling apparatus may be at a rate greater than 500 barrels of fluid per day (about 3000 liters per day) per hose. The hydraulic fluid may include more than 80% water by volume, although highly compressed gasses may be used.
At block 1006, a determination is made as to whether multiple drilling apparatuses were placed in the hole. For example, the high-flow network may have small lateral wells at a frequency of about one small lateral well per every five to 20 meters along the primary wellbore. Each of the small lateral wells would penetrate into the formation along a pathline that may be 5 meters to 50 meters, or greater, as determined by the length of the flexible hose used.
At block 1008, the next set of small lateral wells to be drilled is staged and steps 1004 through 1006 are repeated to drill the small lateral wells. For example, two lateral wells may be concurrently drilled at each stage. In other embodiments, four, six, ten, or any other number of holes may be concurrently drilled, depending on the pressure capacity of the pumps for the hydraulic fluid. The drilling process may be repeated successively in stages within the same wellbore. In one embodiment, the process could be repeated by first drilling a multi-lateral well off of a vertical well. Then a single primary wellbore with accompanying hoses and apparatuses could be installed. Subsequently, the first stage of generating a high-flow network could be performed as previously described. The first single primary wellbore could then be sealed off with a ball seal and a second primary wellbore could then be installed in one of the multi-lateral well offshoots. The process in blocks 1004 through 1008 could then be repeated. In another embodiment a single primary wellbore could be installed into a single horizontal or vertical well. Within the primary wellbore there could be multiple types of seals between the high-pressure flexible hoses and the inner annulus of the primary wellbore. These seals could be designed to rupture at different pressures or after varying exposure to chemicals such as an acid or by a combination thereof. This would enable a single stage of generating a high-flow network to be completed from a first portion of the primary wellbore, subsequently sealing the first portion of the primary wellbore with a seal such as a ball seal, and subsequently rupturing or degrading seals in a second portion of the primary wellbore, completing a second stage of generating a high-flow network and repeating.
At block 1010, drilling is finished, and the flexible hoses are abandoned in the formation. As the small lateral wells have a larger diameter than the flexible hoses, an enhanced flow path will remain. However, at block 1012, a determination may be made to treat or disintegrate the flexible hoses, depending on the material they are made from. If treating is desired, at block 1014, the treatment is performed. This may be done using a solvent, steam, acid, an oxidizer, or any number of other techniques, depending on the material used for the flexible hoses.
At block 1016, the well is placed in service and hydrocarbons are produced. Depending on the formation, the hydrocarbons may include natural gas, oil, or a combination thereof. If a geothermal formation has been enhanced using the techniques described herein, two sets of wells with an overlapping network of high flow channels may be used. A first set of wells may be used to inject water into the formation and a second set of wells may be used to produce hot water or steam from the formation.
Embodiments of the invention may include any combinations of the methods and systems shown in the following numbered paragraphs. This is not to be considered a complete listing of all possible embodiments, as any number of variations can be envisioned from the description above.
Further, embodiments of the invention may include any combinations of the methods and systems shown in the following lettered paragraphs. This is not to be considered a complete listing of all possible embodiments, as any number of variations can be envisioned from the description above.
This application claims the benefit of U.S. Provisional Patent Application No. 61/682,626, filed Aug. 13, 2012, and U.S. Provisional Patent Application No. 61/704,118, filed Sep. 21, 2012, the disclosures of which are hereby incorporated by reference.
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/US13/45454 | 6/12/2013 | WO | 00 |
| Number | Date | Country | |
|---|---|---|---|
| 61682626 | Aug 2012 | US | |
| 61704118 | Sep 2012 | US |
