US20110005762A1

US20110005762A1 - Forming Multiple Deviated Wellbores

Info

Publication number: US20110005762A1
Application number: US12/500,206
Authority: US
Inventors: James Michael Poole
Original assignee: Individual
Current assignee: Gea Delta Technologies LLC
Priority date: 2009-07-09
Filing date: 2009-07-09
Publication date: 2011-01-13
Also published as: WO2011005271A1

Abstract

A system includes a primary wellbore and a plurality of secondary wellbores. The primary wellbore includes a substantially vertical portion extending from a terranean surface to a predetermined location above a first target subterranean formation; a curved portion coupled to the substantially vertical portion and extending through the first target subterranean formation above a second target subterranean formation containing at least one of oil or gas; and a substantially horizontal portion coupled to the curved portion and extending through the first target subterranean formation and adjacent the second target subterranean formation. The plurality of secondary wellbores are coupled to the primary wellbore and extend angularly downward into the second target subterranean formation.

Description

TECHNICAL BACKGROUND

This disclosure relates to systems and methods for forming wellbores within a subterranean formation and, more particularly, to systems and methods for forming wellbores within one or more subterranean formations utilizing one or more deviated wellbore portions extending from an adjacent geological formation to a hydrocarbon bearing formation.

BACKGROUND

Over the last century, oil and gas has been produced from hydrocarbon-bearing geologic strata (“productive formation”) within the Earth's crust by drilling vertical wellbores, which penetrate these potentially productive layers. In most cases, the productive formations are horizontally-planed layers of solid sedimentary rock generally found at depths from approximately 2,000 feet to 20,000 feet below the surface. These productive formations usually range from 10 to 200 feet in thickness. Thus, it may be typical for a vertically-drilled oil or gas well to have less than one percent of its total wellbore length actually exposed to and in contact with targeted productive formations. Moreover, it may be unusual for any more than ten percent of a vertical wellbore to be exposed to a productive formation.
In recent years, technology, equipment, and processes have been developed which allow oil and gas producers to engage in a process known as “horizontal drilling.” In the horizontal drilling process, drillers may first drill vertically into the Earth to a specified point above a targeted productive formation and then bend, or “deviate,” the wellbore in a controlled manner over a distance of several hundred feet to achieve a horizontal wellbore through the target productive formation. This horizontal drilling process has improved over the years. With these horizontal drilling techniques, wells may now be drilled that contain horizontal wellbores through and exposed to tens, hundreds, and even thousands of feet of the targeted horizontally-planed formation, rather than the typical 10 to 200 feet of exposure achieved with vertical drilling methods. Indeed, horizontal wells may have over fifty percent of their total wellbore length within and exposed to the targeted productive formation.
The basic physics underlying oil and gas production involves a migration of hydrocarbons through permeable rock formations to areas of lower pressure created by a wellbore. These hydrocarbons may then flow through the wellbore's steel piping system known as “casing” and are eventually brought to the surface. Because horizontal wellbores drilled through targeted formations are exposed to more of the targeted formation and may have a much greater proportional exposure to the productive rock, these wells may produce at much higher rates and drain the productive formations much more effectively as compared to vertically drilled wells.
Modern drilling techniques for both vertical and horizontal wells may utilize rotary drilling methods that circulate a fluid, such as, for example, compressed air, foam, a liquid such as water, and/or a liquid with one or more chemical additives (also known as “drilling mud”), through the wellbore as the well is drilled. The compressed air circulating method may generally be more efficient and environmentally friendly than drilling on mud. However, a number of productive formations that may be drilled vertically using the air circulation process may not be easily and/or efficiently drilled horizontally using the air circulation process. The geologic characteristics of these formations and the altered flow dynamics of circulation mediums involved in drilling horizontal wellbores may make horizontal drilling through these formations difficult and expensive. Horizontal wellbores through these formations may thus be difficult to drill even using the less efficient fluid “drilling mud” method.
Various natural gas producing regions of the United States, for example, may contain productive formations with great productive potential but which are composed of a highly organic shale rock that may be unsuitable for horizontal drilling using compressed air circulation drilling processes. In some cases, however, a rock layer directly above or adjacent to the productive formation may be a lesser organic, more brittle, competent rock formation (e.g., shale) that may be well-suited for horizontal drilling using compressed air (or foam) drilling processes.
Furthermore, after completion of the drilling process, certain natural gas wells producing from horizontal shale formations may be stimulated prior to or during the production phase by the use of a hydro-fracturing process. This hydro-fracturing process, often known as “Tracing,” involves the injection of a mixture of proppant (most often sand) and water along with other chemical compounds into the formation, thus creating man-made fractures and increasing the permeability within the rock that allows the natural gas held in the formation to migrate more readily toward the wellbore and eventually be produced at the surface through the wellbore's casing.
During such fracing processes, the amount of fresh water needed to frac a drilled well, such as a horizontally-drilled shale well, may be substantial. For example, a typical hydro-frac process on a horizontal well requires as much as 1,000,000 gallons of water. Some larger horizontal well frac jobs may require as much as 4,000,000 gallons of water. Thus, the use of water in fracing horizontal wells has been perceived as a threat to the fresh water balance of nature in certain river basins. The cost to the well owner to assemble this amount of fresh water at the well site can be very high; in some cases exceeding several hundred thousand dollars. Most of the fresh water that is injected into the well during the fracing process flows back out of the well as “frac water” and returns to the surface after the fracing process is completed. The frac water that returns to the surface may likely contain varied amounts of substances, such as chemicals and compounds used in the fracing process and dissolved solids from naturally occurring substances within the productive formations. These substances can include: certain metal and mineral elements, various chloride compounds, and naturally occurring chemicals, such as barium sulfate. The existence of the now-contaminated water at the surface presents additional economic and regulatory issues. Using current processes and technology, disposal of this frac water can cost substantial sums per well, to say nothing of regulatory concerns generated by the storage, handling, and disposal of the frac water.

SUMMARY

In one general embodiment, a method includes forming a first wellbore portion from a terranean surface to a predetermined depth in or near a first target subterranean formation, where the first wellbore portion has an upper section extending from the terranean surface downward in a substantially vertical manner for at least a portion of the depth to the first targeted subterranean formation. The method includes forming a second wellbore portion coupled to the first wellbore portion, where the second wellbore portion is formed substantially horizontal to and in substantial entirety within the first target subterranean formation. The method further includes forming a plurality of third wellbore portions including a plurality of deviated wellbores extending angularly downward into a lower second target subterranean formation from the second wellbore portion, where the second target subterranean formation includes at least one of oil or gas.
In some specific embodiments, the first wellbore portion may be a slanted wellbore from the terranean surface to the predetermined depth. Further, forming the upper vertical section of the first wellbore portion may include drilling through one or more a geologic formations utilizing air as a drilling fluid. Forming the second wellbore portion may include drilling through the first target subterranean formation utilizing air as a drilling fluid. Forming the plurality of third wellbore portions may include drilling through the second target subterranean formation utilizing air as a drilling fluid. Forming the upper vertical section of the first wellbore portion may include drilling through one or more a geologic formations utilizing foam as a drilling fluid. Forming the second wellbore portion may include drilling through the first target subterranean formation utilizing foam as a drilling fluid. Forming the plurality of third wellbore portions may include drilling through the second target subterranean formation utilizing foam as a drilling fluid.
In certain specific embodiments, the first target subterranean formation may be directly adjacent the second target subterranean formation and between the terranean surface and the second target subterranean formation. In addition, the plurality of deviated wellbores may be formed from the second wellbore portion at a downward angle less than 90 degrees from horizontal. Forming a plurality of third wellbore portions including a plurality of deviated wellbores extending angularly into a second target subterranean formation from the second wellbore portion may include forming a plurality of deviated wellbores extending angularly into the second target subterranean formation from the second wellbore portion and completely through the second target subterranean formation. Forming a plurality of third wellbore portions including a plurality of deviated wellbores extending angularly into a second target subterranean formation from the second wellbore portion may include: forming a first group of deviated wellbores extending angularly into the second target subterranean formation; and forming a second group of deviated wellbores extending angularly into the second target subterranean formation, where the second group of deviated wellbores may be separated from the first group of deviated wellbores by a lateral offset.
The method may further include determining the lateral offset between the first and second groups of deviated wellbores based at least in part on a predetermined fracture process or a predetermined stimulation process for the second target subterranean formation. In addition, forming a first group of deviated wellbores extending angularly into the second target subterranean formation may include forming a first group of deviated wellbores extending angularly into the second target subterranean formation at a first angle from horizontal. Forming a second group of deviated wellbores extending angularly into the second target subterranean formation may include forming a second group of deviated wellbores extending angularly into the second target subterranean formation at a second angle distinct from the first angle. In some embodiments, the method may further include determining the first and second angles based at least in part on a predetermined fracture process or a predetermined stimulation process for the second target subterranean formation.
In some embodiments, the plurality of deviated wellbores may include a first plurality of deviated wellbores and the method may further include: forming a fourth wellbore portion coupled to the first wellbore portion, where the fourth wellbore portion may be radially offset from the second wellbore portion and formed substantially horizontal to and in substantial entirety within the first target subterranean formation; and forming a second plurality of deviated wellbores extending angularly into the second target subterranean formation from the fourth wellbore portion. In specific embodiments, the second target subterranean formation may include a hydrocarbon bearing shale formation. Additionally, at least one of the first wellbore portion, the second wellbore portion, and the plurality of deviated wellbores may be formed by rotary drilling equipment. Forming a plurality of deviated wellbores extending angularly into a second target subterranean formation from the second wellbore portion may include forming a plurality of deviated wellbores extending downwardly into a second target subterranean formation from the second wellbore portion and angularly offset from horizontal and vertical.
In another general implementation, a system includes a primary wellbore and a plurality of secondary wellbores. The primary wellbore includes a substantially vertical portion extending from a terranean surface to a predetermined location above a first target subterranean formation; a curved portion coupled to the substantially vertical portion and extending through the first target subterranean formation above a second target subterranean formation containing at least one of oil or gas; and a substantially horizontal portion coupled to the curved portion and extending through the first target subterranean formation and adjacent the second target subterranean formation. The plurality of secondary wellbores are coupled to the primary wellbore and extend angularly downward into the second target subterranean formation.
In some specific embodiments of the system, the substantially vertical portion of the primary wellbore may be formed by drilling through one or more a geologic formations utilizing air as a drilling fluid. Further, the substantially horizontal portion of the primary wellbore may be formed by drilling through one or more a geologic formations utilizing air as a drilling fluid. At least one of the plurality of secondary wellbores may be formed by drilling through one or more a geologic formations utilizing air as a drilling fluid. The substantially vertical portion of the primary wellbore may be formed by drilling through one or more a geologic formations utilizing foam as a drilling fluid. The substantially horizontal portion of the primary wellbore may be formed by drilling through one or more a geologic formations utilizing foam as a drilling fluid. At least one of the plurality of secondary wellbores may be formed by drilling through one or more a geologic formations utilizing foam as a drilling fluid.
In some embodiments, the first target subterranean formation may be directly adjacent the second target subterranean formation and between the terranean surface and the second target subterranean formation. In addition, the plurality of secondary wellbores may be coupled to the substantially horizontal portion of the primary wellbore. The plurality of secondary wellbores may be formed from the substantially horizontal portion at a downward angle less than 90 degrees from horizontal. At least one of the plurality of secondary wellbores may extend completely through the second target subterranean formation.
In certain embodiments, the plurality of secondary wellbores may include a first group of secondary wellbores extending angularly downward into the second target subterranean formation; and a second group of secondary wellbores extending angularly downward into the second target subterranean formation, where the second group of secondary wellbores may be separated from the first group of secondary wellbores within the second target subterranean formation by a lateral offset. The lateral offset between the first and second groups of secondary wellbores may be based at least in part on a predetermined fracture process or a predetermined stimulation process of the second target subterranean formation. The first group of secondary wellbores may extend angularly downward into the second target subterranean formation at a first angle from horizontal and the second group of secondary wellbores may extend angularly downward into the second target subterranean formation at a second angle from horizontal, where the second angle is distinct from the first angle. In some aspects, the first and second angles may be determined based at least in part on a predetermined fracture process or a predetermined stimulation process of the second target subterranean formation.
In some embodiments, the curved portion may be a first curved portion and the system may further include a second curved portion coupled to the substantially vertical portion and radially offset from the first curved portion around the substantially vertical portion, where the second curved portion extends through the first target subterranean formation above the second target subterranean formation. The system may further include a second substantially horizontal portion coupled to the second curved portion and extending through the first target subterranean formation and adjacent the second target subterranean formation. The system may further include a second plurality of secondary wellbores extending angularly downward into the second target subterranean formation from the second substantially horizontal portion. The second target subterranean formation may include a hydrocarbon bearing shale formation. At least one of the primary wellbore and the plurality of secondary wellbores may be formed by rotary drilling equipment.
Various embodiments of a multiple deviated wellbore system according to the present disclosure may include one or more of the following features. For example, the deviated wellbore system may include one or more horizontally-drilled wellbores drilled through one or more formations located above a targeted productive formation and a number of sharp-dipping wellbores into or through a productive formation. As used herein, “formation” may include one or more portions, or the entirety, of a body, or strata, of rock. The result may allow for easier, more efficient, and economical penetration into the target productive formation, greater efficiency in drilling the target productive formation and easier communication of fractures through and, in some cases, rubbilization of the formation. The deviated wellbore system may also allow for horizontal, or directional, drilling in competent formations (e.g., shale) above a highly organic targeted productive formation. The deviated wellbore system may also include drilling multiple wellbores, or paths, for fracturing, draining, and/or producing into and/or from the productive formation from a long radius horizontal-style wellbore to the productive formation. Thus, the deviated wellbore system may allow an entire drilling process to be conducted using an efficient and environmentally friendly compressed air or foam drilling process for both the horizontal wellbore section and the multiple drainage paths. The deviated wellbore system may result in an economic and environmentally efficient drilling process for horizontal wells that are developed to produce hydrocarbons (e.g., oil and/or gas).
Various embodiments of a multiple deviated wellbore system according to the present disclosure may include one or more of the following features. For example, the deviated wellbore system may allow for savings of millions of gallons of water during a traditional hydraulic fracing process by enabling the use of inert gases or high quality foam, thus eliminating the potential to contaminate the ground water and other sub-surface strata with the foreign hydraulic frac materials. Further, when water is used for a frac process, the deviated wellbore system may allow for the well system to be stimulated using very little water. For instance, the multiple drainage paths may be formed at specific intervals and spacings in order to minimize water requirements. In some cases, the deviated wellbore system may require as little as one percent of the water typically used to frac horizontal shale wells. Additionally, the deviated wellbore system may more quickly and efficiently produce hydrocarbons from a geological formation by, for example, encouraging more efficient rubbilization of the formation between two or more of the drainage paths.
These general and specific aspects may be implemented using a device, system or method, or any combinations of devices, systems, or methods. The details of one or more implementations are set forth in the accompanying drawings and the description below. Other features, objects, and advantages will be apparent from the description and drawings, and from the claims.

DESCRIPTION OF DRAWINGS

FIG. 1 illustrates a side cross-sectional view of a first vertical portion of one embodiment of a deviated wellbore system according to the present disclosure;

FIG. 2 illustrates another side cross-sectional view of a second portion of one embodiment of a deviated wellbore system according to the present disclosure;

FIG. 3 illustrates another side cross-sectional view of a third portion of one embodiment of a deviated wellbore system including a deviated wellbore according to the present disclosure;

FIG. 4 illustrates another side cross-sectional view of a third portion of one embodiment of a deviated wellbore system including a deviated wellbore group according to the present disclosure;

FIGS. 5A-B illustrate additional cross-sectional views of one embodiment of a deviated wellbore system including multiple deviated wellbore groups according to the present disclosure;

FIG. 6 illustrates a side cross-sectional view of one embodiment of a deviated wellbore system including multiple deviated wellbore groups during a fracing, stimulation, or production operations according to the present disclosure; and

FIG. 7 illustrates a plan view of one embodiment of a system including multiple deviated wellbore systems according to the present disclosure.

Like reference symbols in the various drawings indicate like elements.

DETAILED DESCRIPTION

In some embodiments, a deviated wellbore system according to the present disclosure includes an articulated wellbore drilled from the surface to a target geological formation located above the target productive formation. The articulated wellbore may include a substantially vertical portion, a radiused portion, and a substantially horizontal portion landing in the target geological formation to be drilled horizontally. In some embodiments, the target geological formation is located adjacent a production formation containing one or more hydrocarbons, such as oil or gas. In some embodiments, the production formation may be a formation containing natural gas such as a shale formation, siltstone, sandstone matrix or limestone matrix. The deviated wellbore system may also include one or more deviated wellbores, or completion paths (e.g., production, fracture, stimulation paths), drilled from the substantially horizontal portion of the wellbore into the productive formation. Completion operations may be conducted through the deviated wellbores to more efficiently produce the hydrocarbons.
FIG. 1 illustrates a portion of one embodiment of a deviated wellbore system 10 according to the present disclosure. Generally, each deviated wellbore system 10 accesses one or more subterranean formations, and provides easier and more efficient production of any hydrocarbons located in such subterranean formations. Further, the deviated wellbore system 10 may allow for easier and more efficient fracing or stimulation operations. As illustrated in FIG. 1, the deviated wellbore system 10 includes a drilling assembly 15 deployed on a terranean surface 12. The drilling assembly 15 may be used to form a vertical wellbore portion 20 extending from the terranean surface 12 and through one or more geological formations in the Earth. One or more subterranean formations, such as productive formation 55, are located under the terranean surface 12. As will be explained in more detail below, one or more wellbore casings, such as a surface casing 30 and intermediate casing 35, may be installed in at least a portion of the vertical wellbore portion 20.
In some embodiments, the drilling assembly 15 may be deployed on a body of water rather than the terranean surface 12. For instance, in some embodiments, the terranean surface 12 may be an ocean, gulf, sea, or any other body of water under which hydrocarbon-bearing formations may be found. In short, reference to the terranean surface 12 includes both land and water surfaces and contemplates forming and/or developing one or more deviated wellbore systems 10 from either or both locations.
Generally, the drilling assembly 15 may be any appropriate assembly or drilling rig used to form wellbores or boreholes in the Earth. The drilling assembly 15 may use traditional techniques to form such wellbores, such as the vertical wellbore portion 20, or may use nontraditional or novel techniques. In some embodiments, the drilling assembly 15 may use rotary drilling equipment to form such wellbores. Rotary drilling equipment is known and may consist of a drill string 17 and a bottom hole assembly 45. In some embodiments, the drilling assembly 15 may consist of a rotary drilling rig. Rotating equipment on such a rotary drilling rig may consist of components that serve to rotate a drill bit, which in turn forms a wellbore, such as the vertical wellbore portion 20, deeper and deeper into the ground. Rotating equipment consists of a number of components (not all shown here), which contribute to transferring power from a prime mover to the drill bit itself. The prime mover supplies power to a rotary table, or top direct drive system, which in turn supplies rotational power to the drill string 17. The drill string 17 is typically attached to the drill bit within the bottom hole assembly 45. A swivel, which is attached to hoisting equipment, carries much, if not all of, the weight of the drill string 17, but may allow it to rotate freely.
The drill string 17 typically consists of sections of heavy steel pipe, which are threaded so that they can interlock together. Below the drill pipe are one or more drill collars, which are heavier, thicker, and stronger than the drill pipe. The threaded drill collars help to add weight to the drill string 17 above the drill bit to ensure that there is enough downward pressure on the drill bit to allow the bit to drill through the one or more geological formations. The number and nature of the drill collars on any particular rotary rig may be altered depending on the downhole conditions experienced while drilling.
The drill bit is typically located within or attached to the bottom hole assembly 45, which is located at a downhole end of the drill string 17. The drill bit is primarily responsible for making contact with the material (e.g., rock) within the one or more geological formations and drilling through such material. According to the present disclosure, a drill bit type may be chosen depending on the type of geological formation encountered while drilling. For example, different geological formations encountered during drilling may require the use of different drill bits to achieve maximum drilling efficiency. Drill bits may be changed because of such differences in the formations or because the drill bits experience wear. Although such detail is not critical to the present disclosure, there are generally four types of drill bits, each suited for particular conditions. The four most common types of drill bits consist of: delayed or dragged bits, steel to rotary bits, polycrystalline diamond compact bits, and diamond bits. Regardless of the particular drill bits selected, continuous removal of the “cuttings” is essential to rotary drilling.
The circulating system of a rotary drilling operation, such as the drilling assembly 15, may be an additional component of the drilling assembly 15. Generally, the circulating system has a number of main objectives, including cooling and lubricating the drill bit, removing the cuttings from the drill bit and the wellbore, and coating the walls of the wellbore with a mud type cake. The circulating system consists of drilling fluid, which is circulated down through the wellbore throughout the drilling process. Typically, the components of the circulating system include drilling fluid pumps, compressors, related plumbing fixtures, and specialty injectors for the addition of additives to the drilling fluid. In some embodiments, such as, for example, during a horizontal or directional drilling process, downhole motors may be used in conjunction with or in the bottom hole assembly 45. Such a downhole motor may be a mud motor with a turbine arrangement, or a progressive cavity arrangement, such as a Moineau motor. These motors receive the drilling fluid through the drill string 17 and rotate to drive the drill bit or change directions in the drilling operation.
In many rotary drilling operations, the drilling fluid is pumped down the drill string 17 and out through ports or jets in the drill bit. The fluid then flows up toward the surface 12 within an annular space (i.e., an annulus) between the wellbore portion 20 and the drill string 17, carrying cuttings in suspension to the surface. The drilling fluid, much like the drill bit, may be chosen depending on the type of geological conditions found under subterranean surface 12. For example, certain geological conditions found and some subterranean formations may require that a liquid, such as water, be used as the drilling fluid. In such situations, in excess of 100,000 gallons of water may be required to complete a drilling operation. If water by itself is not suitable to carry the drill cuttings out of the bore hole or is not of sufficient density to control the pressures in the well, clay additives (bentonite) or polymer-based additives, may be added to the water to form drilling fluid (i.e., drilling mud) As noted above, there may be concerns regarding the use of such additives in underground formations which may be adjacent to or near subterranean formations holding fresh water.
In some embodiments, the drilling assembly 15 and the bottom hole assembly 45 may operate with air or foam as the drilling fluid. For instance, in an air rotary drilling process, compressed air lifts the cuttings generated by the drill bit vertically upward through the annulus to the terranean surface 12. Large compressors may provide air that is then forced down the drill string 17 and eventually escapes through the small ports or jets in the drill bit. Cuttings removed to the terranean surface 12 are then collected. Air drilling may include certain advantages over drilling with a liquid as the drilling fluid. For instance, air drilling may allow for better hole cleaning as well as better indications of the downhole conditions in the wellbore portion 20. Further, air drilling may allow for faster indication of water or hydrocarbons being produced into the wellbore portion 20. Additionally, air drilling often allows for lower pollution, faster penetration into the one or more geological formations, and greater drill bit life. Air drilling may also be advantageous, because air is readily available.
As noted above, the choice of drilling fluid may depend on the type of geological formations encountered during the drilling operations. Further, this decision may be impacted by the type of drilling, such as vertical drilling, horizontal drilling, or directional drilling. In some cases, for example, certain geological formations may be more amenable to air drilling when drilled vertically as compared to drilled directionally or horizontally. As one example of such considerations, certain areas of the United States include a hydrocarbon bearing formation called the Marcellus shale formation. The Marcellus shale formation may typically require the use of a liquid, such as water, to be used as the drilling fluid in drilling horizontally. Geological formations surrounding the Marcellus shale formation, however, may be more amenable to the use of air when drilling horizontally. For example, in some areas, the Marcellus shale formation is located directly adjacent to and under the Hamilton shale formation. The Hamilton shale formation may be efficiently drilled using air as the drilling fluid. Further, the Hamilton shale formation is often located directly adjacent to and under a limestone formation called the Tully lime. The Tully lime may also be efficiently drilled on air. Further, highly organic formations such as the Marcellus shale formation, may be unsuitable for horizontal drilling using compressed air circulation drilling processes. Competent shale formations, such as the Hamilton shale formation, may be directionally drilled on air with significantly greater efficiency and less use of resources such as water. Although one example group of geological strata has been described above, other groups exist and the present disclosure contemplates that one or more embodiments of the deviated wellbore system 10 may be formed and utilized in any particular geologic strata.
As illustrated in FIG. 1, the bottom hole assembly 45, including the drill bit, drills or creates the vertical wellbore portion 20, which extends from the terranean surface 12 towards the target subterranean formation 50 and the productive formation 55. In some embodiments, the target subterranean formation 50 may be a geological formation amenable to air drilling. In addition, in some embodiments, the productive formation 55 may be a geological formation that is less amenable to air drilling processes. As illustrated in FIG. 1, the productive formation 55 is directly adjacent to and under the target formation 50. Alternatively, in some embodiments, there may be one or more intermediate subterranean formations (e.g., different rock or mineral formations) between the target subterranean formation 50 and the productive formation 55.
In some embodiments of the deviated wellbore system 10, the vertical wellbore portion 20 may be cased with one or more casings. As illustrated, the vertical wellbore portion 20 includes a conductor casing 25, which extends from the terranean surface 12 shortly into the Earth. A portion of the vertical wellbore portion 20 enclosed by the conductor casing 25 may be a large diameter borehole. For instance, this portion of the vertical wellbore portion 20 may be a 17-½“ borehole with a 13-⅜” conductor casing 25. Additionally, in some embodiments, the vertical wellbore portion 20 may be offset from vertical (e.g., a slant wellbore). Even further, in some embodiments, the vertical wellbore portion 20 may be a stepped wellbore, such that a portion is drilled vertically downward and then curved to a substantially horizontal wellbore portion. The substantially horizontal wellbore portion may then be turned downward to a second substantially vertical portion, which is then turned to a second substantially horizontal wellbore portion. Additional substantially vertical and horizontal wellbore portions may be added according to, for example, the type of terranean surface 12, the depth of one or more target subterranean formations, the depth of one or more productive subterranean formations, and/or other criteria.
Downhole of the conductor casing 25 may be the surface casing 30. The surface casing 30 may enclose a slightly smaller borehole and protect the vertical wellbore portion 20 from intrusion of, for example, freshwater aquifers located near the terranean surface 12. The vertical wellbore portion 20 may than extend vertically downward toward a kickoff point 47, which may be between 500 and 1,000 feet above the target subterranean formation 50. This portion of the vertical wellbore portion 20 may be enclosed by the intermediate casing 35. In some embodiments, the borehole diameter of the vertical wellbore portion 20 in this portion is approximately 6-¼″. Alternatively, the diameter of the vertical wellbore portion 20 at any point within its length, as well as the casing size of any of the aforementioned casings, may be an appropriate size depending on the drilling process.
Upon reaching the kickoff point 47, drilling tools such as logging equipment may be deployed into the wellbore portion 20. At that point, a determination of the exact location of the bottom hole assembly 45 may be made and transmitted to the terranean surface 12. Further, upon reaching the kickoff point 47, the bottom hole assembly 45 may be changed or adjusted such that appropriate directional drilling tools may be inserted into the vertical wellbore portion 20.
FIG. 2 illustrates another portion of one embodiment of a deviated wellbore system 10 according to the present disclosure. For example, FIG. 2 illustrates the deviated wellbore system 10 after a curved wellbore portion 60 and a horizontal wellbore portion 65 have been formed within one or more geological formations. Typically, the curved wellbore portion 60 may be drilled starting from the downhole end of the vertical wellbore portion 20 and deviated from the vertical wellbore portion 20 toward a predetermined azimuth gaining from between 9 and 18 degrees of angle per 100 feet drilled. Alternatively, different predetermined azimuth may be used to drill the curved wellbore portion 60. In drilling the curved wellbore portion 60, the bottom hole assembly 45 often uses measurement-while-drilling (“MWD”) equipment to more precisely determine the location of the drill bit within the one or more geological formations, such as the target subterranean formation 50. Generally, MWD equipment may be utilized to directionally steer the drill bit as it forms the curved wellbore portion 60, as well as the horizontal wellbore portion 65.
The horizontal wellbore portion 65 may typically extend for hundreds, if not thousands, of feet within the target subterranean formation 50. Although FIG. 2 illustrates the horizontal wellbore portion 65 as exactly perpendicular to the vertical wellbore portion 20, it is understood that directionally drilled wellbores, such as the horizontal wellbore portion 65, have some variation in their paths. Thus, the horizontal wellbore portion 65 may include a “zigzag” path yet remain in the target subterranean formation 50. Typically, the horizontal wellbore portion 65 is drilled to a predetermined end point 70, which, as noted above, may be up to thousands of feet from the kickoff point 47. As noted above, in some embodiments, the curved wellbore portion 60 and the horizontal wellbore portion 65 may be formed utilizing an air drilling process that uses air or foam as the drilling fluid.
FIG. 3 illustrates another portion of one embodiment of a deviated wellbore system 10 including a deviated wellbore portion 75 according to the present disclosure. For example, FIG. 3 illustrates the deviated wellbore system 10 once the vertical wellbore portion 20, the curved wellbore portion 60, and the horizontal wellbore portion 65 are completely formed in the one or more geological formations underneath the terranean surface 12, such as the target subterranean formation 50. FIG. 3 also illustrates a deviated wellbore portion 75 formed by drilling from the horizontal wellbore portion 65 into the productive formation 55. Generally, the deviated wellbore portion 75 is a borehole angularly directed downward from the horizontal wellbore portion 65 in the target subterranean formation 50 into the productive formation 55. In some embodiments, the deviated wellbore portion 75 is also formed utilizing an air drilling process. Further, in some embodiments, the deviated wellbore portion 75, once formed, may be used for a variety of purposes. For example, the deviated wellbore portion 75 may be used to introduce fracturing fluid into the productive formation 55, thus creating one or more fracs within the formation 55. In addition, the deviated wellbore portion 75 may be used as a production wellbore, such that hydrocarbons (e.g., oil and gas) may be produced into the deviated wellbore portion 75 and eventually to the terranean surface 12 through the horizontal wellbore portion 65, the curved wellbore portion 60, and the vertical wellbore portion 20. Further, the deviated wellbore portion 75 may be used in stimulation or secondary production processes. For example, an injection fluid, such as carbon dioxide or nitrogen, may be introduced into the productive formation 55 through the deviated wellbore portion 75 to help enhance production of hydrocarbons found in the productive formation 55 to the terranean surface 12.
In some embodiments, the deviated wellbore portion 75 may be formed vertically offset from the horizontal wellbore portion 65. For example, the deviated wellbore portion 75 may be angularly displaced approximately 90 degrees from the horizontal wellbore portion 65. Alternatively, the deviated wellbore portion 75 may be angularly elite displaced from the horizontal wellbore portion 65 less than 90 degrees (e.g., 75 degrees, 60 degrees, 30 degrees). In some embodiments, the deviated wellbore portion 75 may be a 5- 3/4″ borehole. In many instances, the deviated wellbore portion 75 (as well as the curved wellbore portion 60 and the horizontal wellbore portion 65) may be uncased boreholes or include a screen liner instead of traditional casing.
In some embodiments, the deviated wellbore portion 75 may be formed through a portion of the vertical thickness of the productive formation 55. Alternatively, the deviated wellbore portion 75 may be drilled completely through the productive formation 55 and end in, for instance, a geological formation located adjacent to and under the productive formation 55.
FIG. 4 illustrates another portion of one embodiment of a deviated wellbore system 10 including a deviated wellbore group 80 a according to the present disclosure. For example, in some embodiments of the deviated wellbore system 10, multiple deviated wellbore portions 75 may be formed from the horizontal wellbore portion 65 and extending to the productive formation 55. As illustrated in FIG. 4, the deviated wellbore group 80 a may consist of five deviated wellbore portions 75; fewer or greater number of deviated wellbore portions 75 may make up a deviated wellbore group as appropriate. In some embodiments, each deviated wellbore portion 75 drilled within the deviated wellbore group 80 a may be substantially identical. For instance, each deviated wellbore portion 75 within the group 80 a may be angularly displaced from the horizontal wellbore portion 65 at substantially the same angle (A) (e.g., 85 degrees). Further, each deviated wellbore portion 75 may be approximately the same length (L), or in other words, extend into the productive formation 55 the same or substantially the same distance. In addition, each deviated wellbore portion 75 may be laterally spaced a distance (D) from adjacent deviated wellbores along the horizontal wellbore portion 65, where D is substantially equal between successive deviated wellbore portions 75 within the group 80 a.
Alternatively, the aforementioned characteristics of the individual deviated wellbore portions 75 within the deviated wellbore group 80 a may be distinct from wellbore portion 75 to wellbore portion 75. For instance, the angular displacement (A) of each deviated wellbore portion 75 within the group 80 a may be distinct. The length (L) of each deviated wellbore portion 75 within the group 80 a may be distinct. In some embodiments, for example, MWD and logging-while drilling (LWD) technology may be utilized to determine a lower boundary or edge of the productive formation 55. As geological formations such as the productive formation 55 may be undulating and varying in thickness, a true vertical depth (TVD) of such a lower edge may vary along the formation 55. Each deviated wellbore portion 75 may be drilled to approach such a lower edge, thus making the lengths (L) of each deviated wellbore portion 75 vary within the group 80 a. As another example, the spacing (D) between adjacent deviated wellbores portions 75 within the deviated wellbore group 80 a may vary.
Each of these variable and adjustable characteristics may be predetermined prior to drilling the deviated wellbore system 10 or determined during the drilling of the deviated wellbore system 10. For instance, such characteristics (A, L, D), as well as others, may be predetermined according to a planned fracture or stimulation treatment (e.g., type of fracture or injection fluid used in such processes). Alternatively, or in addition, one or more of such characteristics (A, L, D) may be determined during the drilling process according to, for example, the geological characteristics of the target subterranean formation 50, the productive formation 55, or other geologic formations adjacent or near such formations.
FIGS. 5A-B illustrate different views of one embodiment of a deviated wellbore system 10 including multiple deviated wellbore groups 80 a-d according to the present disclosure. With reference to FIG. 5A specifically, a side view of one embodiment of the deviated wellbore system 10 is illustrated. As illustrated, the deviated wellbore system 10 includes deviated wellbore groups 80 a-d. Each deviated wellbore group 80 a-d includes five deviated wellbore portions 75 and each group 80 a-d is laterally offset (O) from adjacent wellbore groups. As with the characteristics A, L, and D above, the offset (O) may be predetermined according to, for instance, a planned fracture treatment (e.g., type of fracture fluid) or stimulation treatment (e.g., acidizing), or even one or more of the other deviated wellbore characteristics, A, L, or D. Alternatively, or in addition, the offset (O) may be determined during the drilling process according to, for example, the geological characteristics of the target subterranean formation 50, the productive formation 55, or other geologic formations adjacent or near such formations. Alternatively, other drilling data, processes, equipment, or experience may determine one or more of the characteristics (A, L, D, O). Of course, the deviated wellbore system 10 may include fewer or greater number of deviated wellbore groups 80 a-d and fewer or greater deviated wellbore portions 75 within each group. In addition, one or more characteristics (A, L, D) of each deviated wellbore portion 75 may vary from group to group.
Turning now to FIG. 5B, a sectional view of the horizontal wellbore portion 65 and deviated wellbore groups 80 a-c along the horizontal wellbore portion 65 is illustrated. As illustrated, the deviated wellbore groups 80 c-d are radially offset from a downward vertical direction. For example, the deviated wellbore group 80 c is offset at one angle (R2) from the vertical down direction. The deviated wellbore group 80 d is offset at another angle (R1) from the vertical down direction. As illustrated, the deviated wellbore group 80 b is not radially offset from vertical down. In short, each deviated wellbore group 80 a-d may be radially offset about the horizontal wellbore portion 65 at similar or distinct values. For instance, in some embodiments, R1 may be equal to approximately 10 degrees from vertical down while R2 may be 15 degrees from vertical down. Such angles R1 and R2 may be any appropriate value depending on, for instance, other characteristics of the deviated wellbores 75, the deviated wellbore system 10, or one or more drilling or completion operations (e.g., fracing, stimulation, production).
FIG. 6 illustrates one embodiment of a deviated wellbore system 10 including multiple deviated wellbore groups 80 a-d during a fracing, stimulation, or production operation according to the present disclosure. As illustrated in FIG. 6, one or more packers 85 and sleeves 90 may be inserted into the horizontal wellbore portion 65 via the vertical wellbore portion 20. As used herein, the terms “packer” and “sleeve” mean any generic or application specific packer and sleeve, respectively. In other words, the packer 85 may generally be any drilling process device that can be inserted into a wellbore that may have a smaller initial outside diameter and may then expand externally to seal the wellbore and/or any completion process device that may isolate an annulus from a production conduit, thus enabling controlled production, injection or treatment. The sleeve 90 may generally be any device that may provide a flow path between a production conduit and an annulus, such as a sliding sleeve that incorporates a system of ports that can be opened or closed by a sliding component.
As illustrated, the packers 85 may be arranged between each deviated wellbore group 80 a-d such that one or more of the groups 80 a-d may be isolated from one or more other groups 80 a-d. Thus, hydrocarbon production, fracture generation, or stimulation operations may be completed on each deviated wellbore group or multiple deviated wellbore groups, as appropriate. Further, each sleeve 90 may be positioned at an intersection of a particular deviated wellbore group 80 a-d and the horizontal wellbore portion 65, thus allowing controlled production, fracing, and/or stimulation from each deviated wellbore group 80 a-d. FIG. 6, therefore, illustrates some example arrangements and operations of the packers 85 and the sleeves 90. But many other operations and/or downhole tools may be used in conjunction with the deviated wellbore system 10, the deviated wellbore groups 80 a-d, and the deviated wellbores 75, as appropriate.
FIG. 7 illustrates a plan view of one embodiment of a system 700 including multiple deviated wellbore systems 710 a-b according to the present disclosure. Generally, FIG. 7 illustrates multiple deviated wellbore systems 710 a-b that share a common vertical wellbore portion 720. Thus, the multiple systems 710 a-b (as well as future deviated wellbore systems 710 c-d) may be drilled from a single vertical wellbore portion 720, thus minimizing the number of surface disturbances and drilling operations. As illustrated, the deviated wellbore system 710 a includes the vertical wellbore portion 720, a curved wellbore portion 760 a, a horizontal wellbore portion 765 a, and multiple deviated wellbore portions 775 within multiple deviated wellbore groups 780 a 1 through 780 a 3. The deviated wellbore system 710 a, the deviated wellbore groups 780 a 1 through 780 a 3 and the deviated wellbore portions 775 may be identical or substantially identical to such components as described above with reference to FIGS. 1-6. Further, as illustrated, the deviated wellbore system 710 b includes the vertical wellbore portion 720, a curved wellbore portion 760 b, a horizontal wellbore portion 765 b, and multiple deviated wellbore portions 775 within multiple deviated wellbore groups 780 b 1 through 780 b 4. As may be recognized, future deviated wellbore systems, such as systems 710 c-d, may also share the vertical wellbore portion 720. In addition, fewer or greater systems 710 may share the vertical wellbore portion 720 as are shown in FIG. 7. Further, as illustrated, the deviated wellbore system 710 a and the deviated wellbore system 710 b are approximately 180 degrees apart with respect to the vertical wellbore portion 720. Alternatively, the systems 710 a and 710 b, or any number of deviated wellbore systems, may be less than 180 degrees apart with respect to the vertical wellbore portion 720 (e.g., 15 degrees, 20 degrees, etc.).
A number of embodiments have been described. Nevertheless, it will be understood that various modifications may be made. For instance FIGS. 1-6 illustrate one embodiment of a deviated wellbore system in which a horizontal wellbore is drilled within a target subterranean formation adjacent and above a productive formation. In some embodiments, the horizontal wellbore may be drilled into a target subterranean formation located adjacent and below a productive formation. Thus, deviated wellbores formed from the horizontal wellbore and extending into the productive formation may be angularly displaced vertically upward from the horizontal wellbore. Such embodiments may be implemented, for instance, when the productive formation contains heavy oil or other viscous hydrocarbon. After completion of such a deviated wellbore system, such heavy oil may be produced by, for example, injecting steam or other high-temperature fluid into the productive formation from the deviated wellbores, such as, for example, in steam assisted gravity drainage (SAGD) operations. Accordingly, other embodiments are within the scope of the following claims.

Claims

1. A method comprising:

forming a first wellbore portion from a terranean surface to a predetermined depth in or near a first target subterranean formation, the first wellbore portion having an upper section extending from the terranean surface downward in a substantially vertical manner for at least a portion of the depth to the first targeted subterranean formation;

forming a second wellbore portion coupled to the first wellbore portion, the second wellbore portion formed substantially horizontal to and in substantial entirety within the first target subterranean formation; and

forming a plurality of third wellbore portions comprising a plurality of deviated wellbores extending angularly downward into a lower second target subterranean formation from the second wellbore portion, the second target subterranean formation including at least one of oil or gas.

2. The method of claim 1, wherein the first wellbore portion comprises a slanted wellbore from the terranean surface to the predetermined depth.

3. The method of claim 1, wherein forming the upper vertical section of the first wellbore portion comprises drilling through one or more a geologic formations utilizing air as a drilling fluid.

4. The method of claim 1, wherein forming the second wellbore portion comprises drilling through the first target subterranean formation utilizing air as a drilling fluid.

5. The method of claim 1, wherein forming the plurality of third wellbore portions comprises drilling through the second target subterranean formation utilizing air as a drilling fluid.

6. The method of claim 1, wherein forming the upper vertical section of the first wellbore portion comprises drilling through one or more a geologic formations utilizing foam as a drilling fluid.

7. The method of claim 1, wherein forming the second wellbore portion comprises drilling through the first target subterranean formation utilizing foam as a drilling fluid.

8. The method of claim 1, wherein forming the plurality of third wellbore portions comprises drilling through the second target subterranean formation utilizing foam as a drilling fluid.

9. The method of claim 1, wherein the first target subterranean formation is directly adjacent the second target subterranean formation and between the terranean surface and the second target subterranean formation.

10. The method of claim 1, wherein the plurality of deviated wellbores are formed from the second wellbore portion at a downward angle less than 90 degrees from horizontal.

11. The method of claim 1, wherein forming a plurality of third wellbore portions comprising a plurality of deviated wellbores extending angularly into a second target subterranean formation from the second wellbore portion comprises forming a plurality of deviated wellbores extending angularly into the second target subterranean formation from the second wellbore portion and completely through the second target subterranean formation.

12. The method of claim 1, wherein forming a plurality of third wellbore portions comprising a plurality of deviated wellbores extending angularly into a second target subterranean formation from the second wellbore portion comprises:

forming a first group of deviated wellbores extending angularly into the second target subterranean formation; and

forming a second group of deviated wellbores extending angularly into the second target subterranean formation, the second group of deviated wellbores separated from the first group of deviated wellbores by a lateral offset.

13. The method of claim 12 further comprising determining the lateral offset between the first and second groups of deviated wellbores based at least in part on a predetermined fracture process or a predetermined stimulation process for the second target subterranean formation.

14. The method of claim 12, wherein forming a first group of deviated wellbores extending angularly into the second target subterranean formation comprises forming a first group of deviated wellbores extending angularly into the second target subterranean formation at a first angle from horizontal; and

forming a second group of deviated wellbores extending angularly into the second target subterranean formation comprises forming a second group of deviated wellbores extending angularly into the second target subterranean formation at a second angle distinct from the first angle.

15. The method of claim 14 further comprising determining the first and second angles based at least in part on a predetermined fracture process or a predetermined stimulation process for the second target subterranean formation.

16. The method of claim 1, the plurality of deviated wellbores comprising a first plurality of deviated wellbores, the method further comprising:

forming a fourth wellbore portion coupled to the first wellbore portion, the fourth wellbore portion radially offset from the second wellbore portion and formed substantially horizontal to and in substantial entirety within the first target subterranean formation; and

forming a second plurality of deviated wellbores extending angularly into the second target subterranean formation from the fourth wellbore portion.

17. The method of claim 1, wherein the second target subterranean formation comprises a hydrocarbon bearing shale formation.

18. The method of claim 1, wherein at least one of the first wellbore portion, the second wellbore portion, and the plurality of deviated wellbores are formed by rotary drilling equipment.

19. The method of claim 1, wherein forming a plurality of deviated wellbores extending angularly into a second target subterranean formation from the second wellbore portion comprises forming a plurality of deviated wellbores extending downwardly into a second target subterranean formation from the second wellbore portion and angularly offset from horizontal and vertical.

20. A system comprising:

a primary wellbore comprising:

a substantially vertical portion extending from a terranean surface to a predetermined location above a first target subterranean formation;

a curved portion coupled to the substantially vertical portion and extending through the first target subterranean formation above a second target subterranean formation containing at least one of oil or gas; and

a substantially horizontal portion coupled to the curved portion and extending through the first target subterranean formation and adjacent the second target subterranean formation; and

a plurality of secondary wellbores coupled to the primary wellbore and extending angularly downward into the second target subterranean formation.

21. The system of claim 20, wherein the substantially vertical portion of the primary wellbore is formed by drilling through one or more a geologic formations utilizing air as a drilling fluid.

22. The system of claim 20, wherein the substantially horizontal portion of the primary wellbore is formed by drilling through one or more a geologic formations utilizing air as a drilling fluid.

23. The system of claim 20, wherein at least one of the plurality of secondary wellbores is formed by drilling through one or more a geologic formations utilizing air as a drilling fluid.

24. The system of claim 20, wherein the substantially vertical portion of the primary wellbore is formed by drilling through one or more a geologic formations utilizing foam as a drilling fluid.

25. The system of claim 20, wherein the substantially horizontal portion of the primary wellbore is formed by drilling through one or more a geologic formations utilizing foam as a drilling fluid.

26. The system of claim 20, wherein at least one of the plurality of secondary wellbores is formed by drilling through one or more a geologic formations utilizing foam as a drilling fluid.

27. The system of claim 20, wherein the first target subterranean formation is directly adjacent the second target subterranean formation and between the terranean surface and the second target subterranean formation.

28. The system of claim 20, wherein the plurality of secondary wellbores are coupled to the substantially horizontal portion of the primary wellbore.

29. The system of claim 28, wherein the plurality of secondary wellbores are formed from the substantially horizontal portion at a downward angle less than 90 degrees from horizontal.

30. The system of claim 20, wherein at least one of the plurality of secondary wellbores extends completely through the second target subterranean formation.

31. The system of claim 20, wherein the plurality of secondary wellbores comprise:

a first group of secondary wellbores extending angularly downward into the second target subterranean formation; and

a second group of secondary wellbores extending angularly downward into the second target subterranean formation, the second group of secondary wellbores separated from the first group of secondary wellbores within the second target subterranean formation by a lateral offset.

32. The system of claim 31, wherein the lateral offset between the first and second groups of secondary wellbores is based at least in part on a predetermined fracture process or a predetermined stimulation process of the second target subterranean formation.

33. The system of claim 31, wherein the first group of secondary wellbores extend angularly downward into the second target subterranean formation at a first angle from horizontal and the second group of secondary wellbores extend angularly downward into the second target subterranean formation at a second angle from horizontal, the second angle distinct from the first angle.

34. The system of claim 33, wherein the first and second angles are determined based at least in part on a predetermined fracture process or a predetermined stimulation process of the second target subterranean formation.

35. The system of claim 20, the curved portion comprising a first curved portion, the system further comprising:

a second curved portion coupled to the substantially vertical portion and radially offset from the first curved portion around the substantially vertical portion, the second curved portion extending through the first target subterranean formation above the second target subterranean formation;

a second substantially horizontal portion coupled to the second curved portion and extending through the first target subterranean formation and adjacent the second target subterranean formation; and

a second plurality of secondary wellbores extending angularly downward into the second target subterranean formation from the second substantially horizontal portion.

36. The system of claim 20, wherein the second target subterranean formation comprises a hydrocarbon bearing shale formation.

37. The system of claim 20, wherein at least one of the primary wellbore and the plurality of secondary wellbores are formed by rotary drilling equipment.