Patent Application
20230184077
This disclosure relates to downhole phase separation in subterranean formations, and in particular, in deviated wells.
Gas reservoirs that have naturally low reservoir pressures can be susceptible to liquid loading at some point in the production life of a well due to the reservoir's inability to provide sufficient pressure to carry wellbore liquids to the surface. As liquids accumulate, slug flow of gas and liquid phases can be encountered, especially in deviated wells. As a deviated well turns vertically at a heel, gas can segregate and migrate upward in comparison to liquid due to the effects of gravity and collect to form gas slugs. Slug flows are unstable and can bring solids issues and pumping interferences, which can result in an increase in operating expenses, excessive workover costs, and insufficient pressure drawdown.
This disclosure describes technologies relating to downhole phase separation in subterranean formations, and in particular, in deviated wells. Certain aspects of the subject matter described can be implemented as a system. The system includes a packer, a first tubular, a second tubular, and a connector. The packer is configured to be disposed in a deviated portion of a well formed in a subterranean formation. The packer is configured to form a seal with an inner wall of the well. The first tubular extends through the packer and has a cross-sectional flow area that is smaller than a cross-sectional flow area of the well. The first tubular includes a first inlet and a first outlet portion. The first inlet is configured to receive a wellbore fluid. The first outlet portion is configured to induce separation of a gaseous portion of the wellbore fluid from a remainder of the wellbore fluid, such that the gaseous portion flows uphole through an annulus between the inner wall of the well and the first tubular. The second tubular includes a second inlet and a second outlet. The second inlet is configured to receive at least a liquid portion of the remainder of the wellbore fluid. The second outlet is configured to discharge the liquid portion of the remainder of the wellbore fluid. The connector is coupled to the first tubular and the second tubular. The connector is coupled to the first outlet portion of the first tubular, such that the connector is configured to prevent flow of the wellbore fluid from the first tubular through the connector. The connector is configured to fluidically connect the second tubular to a downhole artificial lift system disposed within the well, uphole of the connector. A sump for accumulation of solid material from the wellbore fluid is defined by a region of the annulus between the inner wall of the well and the first tubular, downhole of the second inlet of the second tubular and uphole of the packer.
This, and other aspects, can include one or more of the following features. The deviated portion of the well in which the packer is disposed can have a deviation angle in a range of from 70 degrees (°) to 90° (horizontal). The first tubular can include a first portion near the first inlet. The first portion can have a first deviation angle. The first outlet portion can have a second deviation angle that is less than the first deviation angle. The first outlet portion of the first tubular can define perforations. The perforations can be configured to induce separation of the gaseous portion of the wellbore fluid from the remainder of the wellbore fluid as the wellbore fluid flows through the perforations. The second tubular can have a cross-sectional flow area that is smaller than the cross-sectional flow area of the first tubular. The first tubular can extend past the packer. The first inlet can be positioned downhole in comparison to the packer.
Certain aspects of the subject matter described can be implemented as a system. The system includes a packer, a first tubular, and a second tubular. The packer is configured to be disposed in a deviated portion of a well formed in a subterranean formation. The packer is configured to form a seal with an inner wall of the well. The first tubular extends through the packer. The first tubular has a cross-sectional flow area that is smaller than a cross-sectional flow area of the well. The first tubular includes a first inlet and a first outlet. The first inlet is configured to receive a wellbore fluid. The first outlet is configured to discharge the wellbore fluid into an annulus within the well, uphole of the packer. The second tubular is coupled to the first tubular. The second tubular includes a second inlet and a second outlet. The second inlet is configured to receive at least a liquid portion of the wellbore fluid. The second outlet is configured to discharge the liquid portion of the wellbore fluid to a downhole artificial lift system disposed within the well. The first tubular and the second tubular share a common wall that defines a divided section. The first outlet of the first tubular is disposed at an uphole end of the divided section. The second inlet of the second tubular is disposed at a downhole end of the divided section. A sump for accumulation of solid material from the wellbore fluid is defined by a region of an annulus between the inner wall of the well and the first tubular, downhole of the second inlet of the second tubular and uphole of the packer.
This, and other aspects, can include one or more of the following features. The deviated portion of the well in which the packer is disposed can have a deviation angle in a range of from 70 degrees (°) to 90° (horizontal). The first tubular can include a first portion near the first inlet. The first portion can have a first deviation angle. The first tubular can include a second portion near the first outlet. The second portion can have a second deviation angle less than the first deviation angle. The second tubular can have a cross-sectional flow area that is smaller than the cross-sectional flow area of the first tubular. The first tubular can extend past the packer. The first inlet can be positioned downhole in comparison to the packer.
Certain aspects of the subject matter described can be implemented as a method. A packer is disposed in a deviated portion of a well formed in a subterranean formation. The packer seals with an inner wall of the well. A first tubular extends through the packer. The first tubular has a cross-sectional flow area that is smaller than a cross-sectional flow area of the well. The first tubular includes a first inlet and a first outlet. The first tubular receives a wellbore fluid via the first inlet. The first outlet discharges the wellbore fluid into an annulus within the well, uphole of the packer. A second tubular is coupled to the first tubular. The second tubular includes a second inlet. The second tubular receives at least a liquid portion of the wellbore fluid via the second inlet. The second tubular directs the liquid portion of the wellbore fluid to a downhole artificial lift system disposed within the well. A sump is defined by a region of an annulus between the inner wall of the well and the first tubular, downhole of the second inlet of the second tubular and uphole of the packer. The sump receives at least a portion of solid material carried by the wellbore fluid.
This, and other aspects, can include one or more of the following features. The deviated portion of the well in which the packer is disposed can have a deviation angle in a range of from 70 degrees (°) to 90° (horizontal). The first tubular can include a first portion near the first inlet. The first portion can have a first deviation angle. The first tubular can include a second portion near the first outlet. The second portion can have a second deviation angle that is less than the first deviation angle. The second tubular can have a cross-sectional flow area that is smaller than the cross-sectional flow area of the first tubular. The first tubular can extend past the packer. The first inlet can be positioned downhole in comparison to the packer. The first tubular and the second tubular can share a common wall that defines a divided section. The first outlet of the first tubular can be disposed at an uphole end of the divided section. The second inlet of the second tubular can be disposed at a downhole end of the divided section. Fluid flowing from the first tubular to the second tubular can flow into the annulus before entering the second tubular. The first tubular and the second tubular can be coupled by a connector. The connector can prevent the wellbore fluid from flowing from the first tubular and through the connector. The connector can fluidically connect the second tubular to the downhole artificial lift system. The first tubular can include multiple outlets. The first outlet can be one of the outlets. The multiple outlets of the first tubular can induce separation of a gaseous portion of the wellbore fluid from a remainder of the wellbore fluid as the wellbore fluid flows out of the first tubular through the multiple outlets.
The details of one or more implementations of the subject matter of this disclosure are set forth in the accompanying drawings and the description. Other features, aspects, and advantages of the subject matter will become apparent from the description, the drawings, and the claims.
A phase separation system includes a seal that seals against a wall of a wellbore. A first tubular extends through the seal. The first tubular includes an inlet downhole of the packer that receives a wellbore fluid. The first tubular includes an outlet uphole of the packer that discharges the wellbore fluid into an annulus between the first tubular and the wall of the wellbore, uphole of the packer. A gaseous portion of the wellbore fluid separates from a remainder of the wellbore fluid and flows uphole through the annulus to the surface. The first tubular is coupled to a second tubular. The second tubular includes an inlet downhole of the outlet of the first tubular and uphole of the packer. The inlet of the second tubular receives at least a liquid portion of the wellbore fluid discharged by the first tubular. The second tubular includes an outlet uphole of the inlet of the second tubular that discharges the liquid portion of the wellbore fluid. The liquid portion of the wellbore fluid discharged by the second tubular flows to a downhole artificial lift system to be produced to the surface. A sump is defined by a region of the annulus downhole of the inlet of the second tubular and uphole of the packer. The sump can accumulate solid material carried by the wellbore fluid.
The subject matter described in this disclosure can be implemented in particular implementations, so as to realize one or more of the following advantages. The phase separation systems described herein can effectively mitigate and/or eliminate downhole slugging issues in wells, and in particular, in deviated wells. The phase separation systems described herein can mitigate and/or eliminate liquid loading issues in wells, and in particular, in deviated wells. The phase separation systems described herein can reduce a cross-sectional flow area of multi-phase wellbore fluids in comparison to a cross-sectional flow area of an annulus of a well for gas flow, which can facilitate downhole gas-liquid separation and also mitigate and/or eliminate gas carry-under and liquid carry-over in wells, and in particular, in deviated wells. The phase separation systems described herein can reduce costs associated with well completion operations.
In some implementations, the well 100 is a gas well that is used in producing hydrocarbon gas (such as natural gas) from the subterranean zones of interest to the surface. While termed a “gas well,” the well need not produce only dry gas, and may incidentally or in much smaller quantities, produce liquid including oil, water, or both. In some implementations, the well 100 is an oil well that is used in producing hydrocarbon liquid (such as crude oil) from the subterranean zones of interest to the surface. While termed an “oil well,” the well not need produce only hydrocarbon liquid, and may incidentally or in much smaller quantities, produce gas, water, or both. The production from the well 100 can be multiphase in any ratio. In some implementations, the production from the well 100 can produce mostly or entirely liquid at certain times and mostly or entirely gas at other times. For example, in certain types of wells it is common to produce water for a period of time to gain access to the gas in the subterranean zone.
The wellbore of the well 100 is typically, although not necessarily, cylindrical. All or a portion of the wellbore is lined with a tubing, such as casing 112. The casing 112 connects with a wellhead at the surface and extends downhole into the wellbore. The casing 112 operates to isolate the bore of the well 100, defined in the cased portion of the well 100 by the inner bore of the casing 112, from the surrounding Earth 108. The casing 112 can be formed of a single continuous tubing or multiple lengths of tubing joined (for example, threadedly) end-to-end. The casing 112 can be perforated in the subterranean zone of interest to allow fluid communication between the subterranean zone of interest and the bore of the casing 112. In some implementations, the casing 112 is omitted or ceases in the region of the subterranean zone of interest. This portion of the well 100 without casing is often referred to as “open hole.”
The wellhead defines an attachment point for other equipment to be attached to the well 100. For example, the well 100 can be produced with a Christmas tree attached to the wellhead. The Christmas tree can include valves used to regulate flow into or out of the well 100. The well 100 includes a downhole artificial lift system 150 residing in the wellbore, for example, at a depth that is nearer to subterranean zone than the surface. The artificial lift system 150, being of a type configured in size and robust construction for installation within a well 100, can include any type of rotating equipment that can assist production of fluids to the surface and out of the well 100 by creating an additional pressure differential within the well 100. For example, the artificial lift system 150 can include a pump, compressor, blower, or multi-phase fluid flow aid.
In particular, casing 112 is commercially produced in a number of common sizes specified by the American Petroleum Institute (the “API”), including 4½, 5, 5½, 6, 6⅝, 7, 7⅝, 7¾, 8⅝, 8¾, 9⅝, 9¾, 9⅞, 10¾, 11¾, 11⅞, 13⅜, 13½, 13⅝, 16, 18⅝, and 20 inches, and the API specifies internal diameters for each casing size. The artificial lift system 150 can be configured to fit in, and (as discussed in more detail below) in certain instances, seal to the inner diameter of one of the specified API casing sizes. Of course, the artificial lift system 150 can be made to fit in and, in certain instances, seal to other sizes of casing or tubing or otherwise seal to a wall of the well 100.
Additionally, the construction of the components of the artificial lift system 150 are configured to withstand the impacts, scraping, and other physical challenges the artificial lift system 150 will encounter while being passed hundreds of feet/meters or even multiple miles/kilometers into and out of the well 100. For example, the artificial lift system 150 can be disposed in the well 100 at a depth of up to 10,000 feet (3,048 meters). Beyond just a rugged exterior, this encompasses having certain portions of any electronics being ruggedized to be shock resistant and remain fluid tight during such physical challenges and during operation. Additionally, the artificial lift system 150 is configured to withstand and operate for extended periods of time (for example, multiple weeks, months or years) at the pressures and temperatures experienced in the well 100, which temperatures can exceed 400 degrees Fahrenheit (° F.)/205 degrees Celsius (° C.) and pressures over 2,000 pounds per square inch gauge (psig), and while submerged in the well fluids (gas, water, or oil as examples). Finally, the artificial lift system 150 can be configured to interface with one or more of the common deployment systems, such as jointed tubing (that is, lengths of tubing joined end-to-end), a sucker rod, coiled tubing (that is, not-jointed tubing, but rather a continuous, unbroken and flexible tubing formed as a single piece of material), or wireline with an electrical conductor (that is, a monofilament or multifilament wire rope with one or more electrical conductors, sometimes called e-line) and thus have a corresponding connector (for example, a jointed tubing connector, coiled tubing connector, or wireline connector).
In some implementations, the artificial lift system 150 can be implemented to alter characteristics of a wellbore by a mechanical intervention at the source. Alternatively, or in addition to any of the other implementations described in this specification, the artificial lift system 150 can be implemented as a high flow, low pressure rotary device for gas flow. Alternatively, or in addition to any of the other implementations described in this specification, the artificial lift system 150 can be implemented in a direct well-casing deployment for production through the wellbore. Other implementations of the artificial lift system 150 as a pump, compressor, or multiphase combination of these can be utilized in the well bore to effect increased well production.
The artificial lift system 150 locally alters the pressure, temperature, flow rate conditions, or a combination of these of the fluid in the well 100 proximate the artificial lift system 150. In certain instances, the alteration performed by the artificial lift system 150 can optimize or help in optimizing fluid flow through the well 100. As described previously, the artificial lift system 150 creates a pressure differential within the well 100, for example, particularly within the locale in which the artificial lift system 150 resides. In some instances, a pressure at the base of the well 100 is a low pressure, so unassisted fluid flow in the wellbore can be slow or stagnant. In these and other instances, the artificial lift system 150 introduced to the well 100 adjacent the perforations can reduce the pressure in the well 100 near the perforations to induce greater fluid flow from the subterranean zone, increase a temperature of the fluid entering the artificial lift system 150 to reduce condensation from limiting production, increase a pressure in the well 100 uphole of the artificial lift system 150 to increase fluid flow to the surface, or a combination of these.
The artificial lift system 150 moves the fluid at a first pressure downhole of the artificial lift system 150 to a second, higher pressure uphole of the artificial lift system 150. The artificial lift system 150 can operate at and maintain a pressure ratio across the artificial lift system 150 between the second, higher uphole pressure and the first, downhole pressure in the wellbore. The pressure ratio of the second pressure to the first pressure can also vary, for example, based on an operating speed of the artificial lift system 150. The artificial lift system 150 can operate in a variety of downhole conditions of the well 100. For example, the initial pressure within the well 100 can vary based on the type of well, depth of the well 100, and production flow from the perforations into the well 100.
The well 100 includes a phase separation system 160. The phase separation system 160 includes a seal 161 integrated or provided separately with a downhole system, as shown with the artificial lift system 150. The seal 161 divides the well 100 into an uphole zone 130 above the seal 161 and a downhole zone 132 below the seal 161. The seal 161 is configured to seal against the wall of the wellbore, for example, against the interior wall of the casing 112 in the cased portions of the well 100 or against the interior wall of the wellbore in the uncased, open hole portions of the well 100. In certain instances, the seal 161 can form a gas- and liquid-tight seal at the pressure differential the artificial lift system 150 creates in the well 100. For example, the seal 161 can be configured to at least partially seal against an interior wall of the wellbore to separate (completely or substantially) a pressure in the well 100 downhole of the seal 161 from a pressure in the well 100 uphole of the seal 161. Although not shown in
The phase separation system 160 includes a first tubular 163, a second tubular 165, and a connector 167. The first tubular 163 extends through the seal 161. The first tubular 163 includes an inlet 163a configured to receive a wellbore fluid 190. The first tubular 163 has a cross-sectional flow area that is smaller than a cross-sectional flow area of the well 100 (for example, the wellbore). The wellbore fluid 190 entering the first tubular 163 via the inlet 163a accelerates due to the decreased cross-sectional flow area. The first tubular 163 includes an outlet portion 163b that is configured to induce separation of a gaseous portion 190a of the wellbore fluid 190 from a remainder of the wellbore fluid 190 (for example, a liquid portion 190b of the wellbore fluid and solid material 190c carried by the wellbore fluid). In some implementations, the outlet portion 163b defines perforations 163c, and the perforations 163c are configured to induce separation of the gaseous portion 190a of the wellbore fluid 190 from the remainder of the wellbore fluid 190 as the wellbore fluid 190 flows through the perforations 163c. For example, the perforations 163c can induce a “bubbling” effect that enhances separation of the gaseous portion 190a of the wellbore fluid 190 from the remainder of the wellbore fluid 190. In some implementations, the first tubular 163 includes a swirl device (not shown), such as helical vanes disposed within the outlet portion 163b of the first tubular 163, which can induce rotation in the wellbore fluid 190 flowing through the first tubular 163. The rotation of the wellbore fluid 190 induced by the swirl device can enhance phase separation via centrifugal force.
The gaseous portion 190a of the wellbore fluid 190 can then flow uphole through an annulus 130a of the uphole zone 130 between the inner wall of the well 100 (for example, the casing 112) and the first tubular 163. In some implementations, as shown in
The second tubular 165 includes an inlet 165a configured to receive at least a liquid portion 190b of the wellbore fluid 190. The second tubular 165 includes an outlet 165b configured to discharge the liquid portion 190b of the wellbore fluid 190. The liquid portion 190b of the wellbore fluid 190 discharged by the outlet 165b of the second tubular 165 flows to the artificial lift system 150 to be produced to the surface. In some implementations, the second tubular 165 has a cross-sectional flow area that is smaller than the cross-sectional flow area of the first tubular 163. Decreasing the cross-sectional flow areas of the first tubular 163 and the second tubular 165 directly increases the cross-sectional flow area of the annulus 130a of the uphole zone 130, which can facilitate the separation of phases (gas from liquid and solid from liquid) of the wellbore fluid 190. In some implementations, the inlet 165a of the second tubular 165 includes a screen (not shown) that is configured to prevent solid material of a certain size from flowing through the screen and into the second tubular 165 via the inlet 165a. The screen can be sized to prevent sand or other particulate matter that is expected to be produced with the production fluid (for example, identified from production data obtained for the well 100) from flowing through the screen and into the second tubular 165 via the inlet 165a.
The connector 167 is coupled to the first tubular 163 and the second tubular 165. The connector 167 is coupled to the outlet portion 163b of the first tubular 163, such that the connector 167 is configured to prevent flow of the wellbore fluid 190 from the first tubular 163 through the connector 167. That is, any fluid that flows into the first tubular 163 via the inlet 163a flows out of the first tubular 163 through the perforations 163c of the outlet portion 163b instead of flowing through the connector 167. The connector 167 is configured to fluidically connect the second tubular 165 to the artificial lift system 150, which is disposed uphole of the connector 167.
A sump 169 of the phase separation system 160 is defined by a region of the annulus 130a of the uphole zone 130 between the inner wall of the well 100 (for example, the casing 112) and the first tubular 163, downhole of the inlet 165a of the second tubular 165 and uphole of the seal 161. The sump 169 can accumulate the solid material 190c carried by the wellbore fluid 190. For example, the solid material 190c carried by the wellbore fluid 190 can flow into the first tubular 163 via the inlet 163a, out of the first tubular 163 via the outlet portion 163b, and settle in the sump 169 due to gravity. The perforations 163c of the outlet portion 163b of the first tubular 163 can be sized, such that the solid material 190c can pass through the perforations 163c without getting lodged/stuck in the perforations 163c. The perforations 163c can be sized to allow sand or other particulate matter (for example, identified from production data obtained for the well 100) to pass through the perforations 163c without getting lodged/stuck in the perforations 163c, so that the sand or other particulate matter can be discharged to the annulus 130a of the uphole zone 130 between the inner wall of the well 100 (for example, the casing 112) and the first tubular 163 and subsequently settle in the sump 169. The perforations 163c of the outlet portion 163b of the first tubular 163 can have any shape, for example, circular or any other geometric shape.
The phase separation system 260 includes a first tubular 263 and a second tubular 265. The first tubular 263 can be substantially similar to the first tubular 163 of the phase separation system 160 shown in
The gaseous portion 190a of the wellbore fluid 190 can then flow uphole through the annulus 230a of the uphole zone 230 between the inner wall of the well 100 (for example, the casing 112) and the first tubular 263. In some implementations, as shown in
The second tubular 265 can be substantially similar to the second tubular 165 of the phase separation system 160 shown in
The second tubular 265 is coupled to the first tubular 263. The first tubular 263 and the second tubular 265 share a common wall 267 that defines a divided section 268. The outlet 263b of the first tubular 263 is disposed at an uphole end of the divided section 268. The inlet 265a of the second tubular 265 is disposed at a downhole end of the divided section 268. Thus, the divided section 268 ensures that fluid flowing from the first tubular 263 to the second tubular 265 (for example, the liquid portion 190b of the wellbore fluid 190) flows out of the first tubular 263 via the outlet 263b and into the annulus 230a before entering the second tubular 265 via the inlet 265a.
A sump 269 of the phase separation system 260 is defined by a region of the annulus 230a of the uphole zone 230 between the inner wall of the well 100 (for example, the casing 112) and the first tubular 263, downhole of the inlet 265a of the second tubular 265 and uphole of the seal 261. The sump 269 can be substantially similar to the sump 169 of the phase separation system 160 shown in
At block 304, a wellbore fluid (such as the wellbore fluid 190) is received by a first tubular (such as the first tubular 163 or 263) via an inlet (such as the inlet 163a or 263a, respectively) of the first tubular 163, 263.
At block 306, the wellbore fluid 190 is discharged by an outlet (such as the outlet portion 163b or outlet 263b) of the first tubular 163, 263 into an annulus (such as the annulus 130a or 230a) within the well 100, uphole of the seal 161, 261. When the method 300 is implemented by the phase separation system 160, the connector 167 prevents the wellbore fluid 190 from flowing from the first tubular 163 and through the connector 167. Instead, any fluid that flows into the first tubular 163 via the inlet 163a flows out of the first tubular 163, for example, through the perforations 163c of the outlet portion 163b. The perforations 163c induce separation of the gaseous portion (such as the gaseous portion 190a) of the wellbore fluid 190 from a remainder of the wellbore fluid 190 (for example, the liquid portion 190b of the wellbore fluid and the solid material 190c carried by the wellbore fluid), as the wellbore fluid 190 flows out of the first tubular 163 through the perforations 163c.
At block 308, at least a liquid portion (such as the liquid portion 190b) of the wellbore fluid 190 is received by a second tubular (such as the second tubular 165 or 265) via an inlet (such as the inlet 165a or 265a, respectively) of the second tubular 165, 265. In some implementations, the inlet 165a, 265a can prevent solid material of a certain size from flowing into the second tubular 165, 265, for example, using a screen. For example, the screen can prevent sand or other particulate matter that is expected to be produced with the production fluid (for example, identified from production data obtained for the well 100) from flowing through the screen and into the second tubular 165, 265 via the inlet 165a, 265a.
At block 310, the liquid portion 190b of the wellbore fluid 190 is directed by the second tubular 165, 265 to a downhole artificial lift system (such as the artificial lift system 150) disposed within the well 100. When the method 300 is implemented by the phase separation system 160, the connector 167 fluidically connects the second tubular 165 to the artificial lift system 150.
At block 312, at least a portion of solid material carried by the wellbore fluid 190 (such as the solid material 190c) is received by a sump (such as the sump 169 or 269).
While this specification contains many specific implementation details, these should not be construed as limitations on the scope of what may be claimed, but rather as descriptions of features that may be specific to particular implementations. Certain features that are described in this specification in the context of separate implementations can also be implemented, in combination, in a single implementation. Conversely, various features that are described in the context of a single implementation can also be implemented in multiple implementations, separately, or in any sub-combination. Moreover, although previously described features may be described as acting in certain combinations and even initially claimed as such, one or more features from a claimed combination can, in some cases, be excised from the combination, and the claimed combination may be directed to a sub-combination or variation of a sub-combination.
As used in this disclosure, the terms “a,” “an,” or “the” are used to include one or more than one unless the context clearly dictates otherwise. The term “or” is used to refer to a nonexclusive “or” unless otherwise indicated. The statement “at least one of A and B” has the same meaning as “A, B, or A and B.” In addition, it is to be understood that the phraseology or terminology employed in this disclosure, and not otherwise defined, is for the purpose of description only and not of limitation. Any use of section headings is intended to aid reading of the document and is not to be interpreted as limiting; information that is relevant to a section heading may occur within or outside of that particular section.
As used in this disclosure, the term “about” or “approximately” can allow for a degree of variability in a value or range, for example, within 10%, within 5%, or within 1% of a stated value or of a stated limit of a range.
As used in this disclosure, the term “substantially” refers to a majority of, or mostly, as in at least about 50%, 60%, 70%, 80%, 90%, 95%, 96%, 97%, 98%, 99%, 99.5%, 99.9%, 99.99%, or at least about 99.999% or more.
As used in this disclosure, the term “deviation angle” is the angle at which a longitudinal axis of a wellbore (or portion of a wellbore that is of interest) diverges from vertical. A deviation angle of 0° or 180° means that the longitudinal axis of the wellbore (or portion of the wellbore that is of interest) is vertical. A deviation angle of 90° means that the longitudinal axis of the wellbore (or portion of the wellbore that is of interest) is horizontal.
Values expressed in a range format should be interpreted in a flexible manner to include not only the numerical values explicitly recited as the limits of the range, but also to include all the individual numerical values or sub-ranges encompassed within that range as if each numerical value and sub-range is explicitly recited. For example, a range of “0.1% to about 5%” or “0.1% to 5%” should be interpreted to include about 0.1% to about 5%, as well as the individual values (for example, 1%, 2%, 3%, and 4%) and the sub-ranges (for example, 0.1% to 0.5%, 1.1% to 2.2%, 3.3% to 4.4%) within the indicated range. The statement “X to Y” has the same meaning as “about X to about Y,” unless indicated otherwise. Likewise, the statement “X, Y, or Z” has the same meaning as “about X, about Y, or about Z,” unless indicated otherwise.
Particular implementations of the subject matter have been described. Other implementations, alterations, and permutations of the described implementations are within the scope of the following claims as will be apparent to those skilled in the art. While operations are depicted in the drawings or claims in a particular order, this should not be understood as requiring that such operations be performed in the particular order shown or in sequential order, or that all illustrated operations be performed (some operations may be considered optional), to achieve desirable results. In certain circumstances, multitasking or parallel processing (or a combination of multitasking and parallel processing) may be advantageous and performed as deemed appropriate.
Moreover, the separation or integration of various system modules and components in the previously described implementations should not be understood as requiring such separation or integration in all implementations, and it should be understood that the described components and systems can generally be integrated together or packaged into multiple products.
Accordingly, the previously described example implementations do not define or constrain the present disclosure. Other changes, substitutions, and alterations are also possible without departing from the spirit and scope of the present disclosure.
