Modified Wellbore Casing Trajectories

Info

Publication number: 20160115743
Type: Application
Filed: Oct 21, 2015
Publication Date: Apr 28, 2016
Inventor: Gary K. Reedy (South Perth)
Application Number: 14/918,918

Abstract

An oil and gas casing includes an upper section, a curved section, and a lower section. The upper section extends down from a seafloor to the curved section. The curved section is curved between the upper section and the lower section. The lower section extends from the curved section toward a reservoir. At least a portion of the upper section includes multiple curved sub-sections.

Description

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application claims priority under 35 U.S.C. Section 119(e) to U.S. Provisional Patent Application No. 62/067,628, filed Oct. 23, 2014, and titled “Modified Wellbore Casing Trajectories,” the entire content of which is incorporated herein by reference.

TECHNICAL FIELD

The present disclosure relates generally to a casing for an oil and gas wellbore and more particularly to an oil and gas wellbore casing that has one or more curved sections.

BACKGROUND

During oil and gas exploration and production, oil or gas typically flows up from a reservoir through a wellbore in a controlled manner. Pre-drill planning for exploration and production wells typically includes extensive and redundant safety systems to reduce the possibility of well blowouts, also referred to as “loss of well control,” to as low as reasonably practical. Since the absolute risk of a blowout cannot be reduced to zero, contingency plans for such an occurrence are commonly included in the plan. Further, government regulators may require evidence of the contingency plans. Such contingency plans may involve estimating the “worst-case” blowout scenario and establishing means for drilling at least one relief well capable of delivering sufficient volumes of high density fluid (“kill fluid”) to kill (i.e., stop) the blowout.

Relief wells are typically planned based on technical analyses conducted using a sophisticated computer fluid flow simulator. Typically, a relief well is drilled to intersect an oil or gas well that is experiencing a blowout condition. For example, a relief well may be drilled by first drilling a vertical shaft followed by an angled section to intersect with the blowout well. Once a relief well is drilled, large volumes of high density kill fluids, such as drilling mud and cement, may be pumped down the relief well into the blowout well in order to stop the blowout. The kill fluid is pumped into the relief well to stop the oil or gas blowout by virtue of the higher density of the kill fluid.

For very high rate gas wells, which in some cases are capable of “worst-case” blowout rates exceeding, for example, one billion cubic feet (BCF) of gas per day at pressure of 14.73 psi and a temperature of 60° F., multiple relief wells may be required to stop the flow from the well experiencing the blowout. However, drilling even a single relief well to intersect the production well can be challenging, particularly under offshore conditions. For example, an offshore drilling rig that is used to drill a relief well has to be a safe distance away from and in safe relative direction with respect to the blowout well. Such safety requirements can add to significant complexity to successfully drilling multiple relief wells.

Further, designing relief wells for very high rate gas wells may have additional challenges. For example, the high velocity gas experienced during a blowout can quickly shear the kill fluid that is pumped through the relief wells into a fine mist that is rapidly lifted out of the wellbore. Thus, very large volumes of high density kill fluids must typically be pumped at high rates to overcome the shearing effect of the high velocity gas and achieve a sufficient hydrodynamic column within the blowout well in order to stop the flow.

Accordingly, reducing the number of relief wells required to successfully stop a blowout is desirable. For example, the capability to stop a blowout using a single relief well reduces the complexity and costs associated with drilling and operating multiple relief wells to stop a blowout at a gas or oil well. Further, reducing the amount and rate of kill fluid needed to effectively stop a production well blowout is desirable.

SUMMARY

The present disclosure relates generally to a casing for an oil and gas wellbore. Deviations in the wellbore casing disposed in a wellbore may allow use of a single relief well to stop a blowout under a worst case scenario. Due to a centrifugal effect introduced by deviations in the casing, the deviations may facilitate gas and liquid/solid phase separation during a well killing operation. In turn, the gas and liquid/solid phase separation may help to increase flow resistance and friction pressure and therefore to facilitate regaining well control. In an example embodiment, an oil and gas casing includes an upper section, a curved section, and a lower section. The upper section extends down from a seafloor to the curved section. The curved section is curved between the upper section and the lower section. The lower section extends from the curved section toward a reservoir. The upper section includes multiple curved sub-sections.

In another example embodiment, an oil and gas casing includes an upper section including a spiral section. The casing further includes a curved section and a lower section. The upper section extends down from a seafloor to the curved section. The curved section is curved between the upper section and the lower section. The lower section extends from the curved section toward a reservoir. The upper section includes a spiral section.

In another example embodiment, a method of drilling an oil or gas well includes drilling an upper section of a wellbore, drilling a curved section of the wellbore, and drilling a lower section of the wellbore. The upper section of the wellbore extends down from a seafloor to the curved section of the wellbore. The lower section of the wellbore extends from the curved section of the wellbore toward a reservoir. The upper section of the wellbore includes curved subsections of the wellbore. The method further includes inserting a casing into the wellbore, where inserting the casing into the wellbore forms curved subsections of the casing in an upper section of the casing.

These and other aspects, objects, features, and embodiments will be apparent from the following description and the appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

Reference will now be made to the accompanying drawings, which are not necessarily drawn to scale, and wherein:

FIG. 1 illustrates an offshore oil and gas operation setup including a casing disposed in a wellbore according to an example embodiment;

FIGS. 2A and 2B illustrate a portion of the upper section of the casing shown in FIG. 1 before and after, respectively, curved subsections are formed in the upper section according to an example embodiment;

FIG. 3 illustrates a portion of the upper section 106 of the casing 102 of FIG. 1 that has spiral sections according to another example embodiment; and

FIG. 4 illustrates a portion of the lower section 108 of the casing 102 of FIG. 1 that has undulations according to an example embodiment.

The drawings illustrate only example embodiments and are therefore not to be considered limiting in scope. The elements and features shown in the drawings are not necessarily to scale, emphasis instead being placed upon clearly illustrating the principles of the example embodiments. Additionally, certain dimensions or placements may be exaggerated to help visually convey such principles. In the drawings, reference numerals designate like or corresponding, but not necessarily identical, elements.

DETAILED DESCRIPTION OF THE EXAMPLE EMBODIMENTS

In the following paragraphs, particular embodiments will be described in further detail by way of example with reference to the drawings. In the description, well-known components, methods, and/or processing techniques are omitted or briefly described. Furthermore, reference to various feature(s) of the embodiments is not to suggest that all embodiments must include the referenced feature(s). The present disclosure refers to oil and gas wellbores generally, however, it should be understood that the disclosure is not limited only to wellbores that are for extracting both oil and gas. Instead, the present disclosure can apply to wellbores for extracting any single resource as well as a variety of resources.

The present disclosure relates to an oil and gas wellbore casing that has one or more curved sections. To illustrate, the rate and volume of kill fluid needed to control a high rate gas well blowout may be reduced by having a wellbore casing that alters the flow conditions within the blowout wellbore as compared to a typical casing used in wellbores. For example, under some conditions, the number of relief wells needed to control a blowout condition may be reduced from multiple relief wells to just a single relief well. By using a wellbore casing that has a trajectory that is different from a typical wellbore casing, the pressure drop within the casing may be increased such that the gas flow eventually stops. The changes in the trajectory of the casing induce changes to the flow regime within the blowout well that increase the pressure drop in the casing and eventually cause the gas flow to cease. As described below, the changes in flow regimes through the casing are caused or enhanced by centrifugal effects in curved sections of the casing.

Turning now to the drawings, FIG. 1 illustrates an offshore oil and gas operation setup 100 including a casing 102 disposed in a wellbore 104 according to an example embodiment. The setup 100 includes an offshore rig 114 and a riser 118 extending down from the offshore rig 114 toward the seafloor 112. As illustrated in FIG. 1, the rig 114 is at the sea surface level 116. For example, the surface level 116 may be approximately 200 meters above the seafloor 112. The setup 100 may also include a wellhead 122.

In some example embodiments, the casing 102 includes an upper section 106, a lower section 108, and a curved section 110. The curved section 110 is between the upper section 106 and the lower section 108. The upper section 106 extends down from the seafloor 112 to the curved section 110. The curved section 110 is curved between the upper section 106 and the lower section 108. The lower section 108 extends from the curved section 110 toward a reservoir. For example, the lower section 108 may extend from the curved section 110 in a direction that is approximately 30 degrees from a vertical axis 120 represented by the angle θ in FIG. 1. To illustrate, the curved section 110 may have a 6-degrees per 100 feet curvature (also, referred to as a build-up rate of a curvature). In general, a build-up rate (in degree per 100 feet) of a curve can be converted to a radius of a curvature R_cin feet (ft) using equation (1) below.

R_c=5730/(build-up rate) Equation (1)

For example, using equation (1), a build-up-rate of 6-degrees per 100 ft corresponds to a 955 feet radius of curvature. Further, a build-up rate of 6-degrees per 100 ft may correspond to the angle θ being 30 degrees for a 500 ft length of the curved section 100.

In some example embodiments, the casing 102 has an inner diameter that allows gas production rate of 300 million standard cubic feet (MMscf) per day or more. For example, the inner diameter of the casing 102 may be approximately 13.5 inches. To illustrate, the diameter of the wellbore 104 may be approximately 20 inches, which allows at least a portion of the casing 102 to be deviated from a center axis of the wellbore 104. Alternatively, the casing 102 may have smaller or larger diameter than 13.5 inches, and the wellbore 104 may have a smaller or larger diameter than 20 inches.

In some example embodiments, the upper section 106 of the casing 102 includes one or more curved subsections. Illustrative examples of the curved subsections of the upper section 106 are described in more detail below with respect to FIGS. 2 and 3. In some example embodiments, the upper section 106 may have a length L of, for example, approximately 1000 meters (i.e., approximately 3281 feet). Alternatively, the length L of the upper section 106 may be shorter or longer than 1000 meters.

In some example embodiments, each curved subsection of the upper section 106 may have a vertical length of approximately 1000 feet. For example, the upper section 106 may include a single curved subsection that has a vertical length of approximately 1000 feet along the length L of the upper section 106. To illustrate, a single curved subsection of the upper section may be proximal to the curved section 110, proximal to the seafloor 112, or approximately equidistant from the curved section 110 and the seafloor 112.

In some example embodiments, the upper section 106 may include multiple curved subsections along a portion of the length L of the upper section 106. For example, the upper section 106 may include two curved subsections, each having a vertical length of approximately 1000 feet. Alternatively, the upper section 106 may include two curved subsections, each having a vertical length that is shorter or longer than 1000 feet.

In some example embodiments, the upper section 106 may include three curved subsections, each having a vertical length of approximately 1000 feet. Alternatively, the upper section 106 may include three curved subsections, each having a vertical length that is significantly shorter or longer than 1000 feet.

In some example embodiments, each curved subsection of the upper section 106 may have at least a 1-degree per 100 ft curvature that corresponds to a 5730 ft radius of curvature. Alternatively, each curved subsection of the upper section 106 may have at least a 2-degree per 100 ft curvature.

During a blowout, the flow in the upper section 106 of the casing 102 is typically annular mist flow. When the upper section 106 does not include the one or more curved subsections, the flow in the upper section 106 may tend to stay as annular mist flow, often resulting in minimal viscous energy loss or associated pressure drop in the casing 102. The curved subsections of the upper section 106 alter the casing trajectory of the upper section 106 relative to a typical vertical straight upper section. In some example embodiments, the upper section 106 may include a spiral section such that each curved subsection of the upper subsection is a section of the spiral section. For example, the upper section 106 may be in the form of a corkscrew spiral (i.e., a helical shape) that introduces a desired level of deviation relative to a vertical straight casing. In some example embodiments, the curved subsections of the upper section 106 may be in the form of horizontal undulations relative to a vertical axis.

In some example embodiments, the curved subsections of the upper section 106 may have a centrifugal effect on a mist flow through the upper section 106. For example, in case of a blowout, mist flow may be the initial flow regime for the upper section 106. To illustrate, during a blowout, the initial flow regime in the upper section 106 may be mostly mist flow such that the mist constitutes no more than approximately 8 percent of the gas and mist combination flowing through the upper section 106. When the kill fluid is introduced into the casing (e.g., at the lower section 108) via a relief well drilled to intersect the wellbore 104 below the casing 102, the deviations (i.e., the curved subsections) in the upper section 106 may have a centrifugal effect on the mixture of gas and kill fluid to effectively separate mist droplets from the flowing multiphase mixture of gas and mist. In turn, the separation of mist droplets from the multiphase mixture may result in segregated flow or slug flow that causes a sufficient pressure drop in the casing 102 to effectively stop the blowout and allow the regaining of well control.

The centrifugal effect caused by a single curved subsection of the upper section 106 can be calculated in terms of equivalent gravitational acceleration using equation (2).

g_b=V²/R_c Equation (2)

In equation (2), g_bis a gravitational acceleration equivalent of a centrifugal effect introduced as a result of a single curved subsection of the upper section 106 of the casing 102; V is the average gas velocity through the curved subsection of the curved section 106; and R_cis the radius of curvature of the curved subsection as may be determined using equation (1).

As illustrated in equation (2), the centrifugal effect exerted on the multiphase mixture flowing through a curved subsection of the upper section 106 is the square of the average gas velocity through the curved subsection divided by the radius of curvature of the curved subsection. During a high rate gas blowout, the velocity through the upper section can approach or even exceed 1000 feet per second. At such velocities, the curved subsections of the upper section may result in a centrifugal effect in excess of the earth's gravitational acceleration of 32 ft/s². Such a centrifugal effect may alter the flow regime through the upper section 106 from annular mist flow to a segregated flow or a slug flow. In the case of a segregated flow, the liquid is against the inner surface of the upper section 106 of the casing 102, and a gas/mist is on the liquid and toward the center line of the upper section 106. During the slug flow, the liquid and gas remain segregated but flow interspersed with respect to each other through the upper section 106 of the casing 102.

Because a segregated flow and a slug flow typically exhibit greater pressure drop than annular mist flow at comparable flow rates, the change in the flow regime resulting from the centrifugal effect may enable stopping a blowout using a single relief well and avoid the need for multiple relief wells. In some example embodiments, under some conditions of blowout flow rate, the centrifugal effect due to the curved subsections of the upper section 106 may result in pressure drop in the casing 102 ranging from approximately 65 psi to over 650 psi depending on the radii of curvature of the curved subsections.

As illustrated in FIG. 1, the casing 102 is disposed in the wellbore 104. In some example embodiments, curved subsections may be formed in the upper section 106 of the casing 102 by drilling the wellbore 104 such that the wellbore 104 has curved sections that correspond to the desired curved subsections in the upper section 106 of the casing 102. To illustrate, once the wellbore 104 is drilled to have a curved section in a portion of the wellbore where the upper section 106 of the casing will be positioned, centralizers may be used around the casing 102 to allow the upper section 106 to have curvatures that substantially conform to the curved sections of the wellbore 104.

In some alternative embodiments, the curved subsections in the upper section 106 may be formed by using de-centralizers (not shown) to deviate portions of the upper section 106 from a vertical axis through a center of the wellbore 104. For example, centralizers (not shown) may be used to keep portions of the upper section 106 centralized within the wellbore 104, and one or more de-centralizers may be used between two centralizers to deviate a portion of the upper section 106 that is between the two centralizers from the vertical axis.

In some example embodiments, the radii of curvature of the curved subsections of the upper section 106 are substantially the same size. For example, the radii of curvature of the curved subsections of the upper section 106 may be large enough such that a single relief well may be used to stop or control a gas blowout through the casing 102. To illustrate, for a particular blowout flow rate, a 955 ft radius of curvature of each curved subsection may be adequate to allow use of a single relief well to control a worst case scenario blowout. The curved subsections may have radii of curvature that are smaller or larger than 955 ft depending on, for example, an expected worst case scenario blowout flow rate.

In some example embodiments, the curved subsections of the upper section 106 that are closer to the curved section 110 may have larger radii of curvature than curved subsections of the upper section 106 that are closer to the seafloor 112. Alternatively, the upper section 106 may include other arrangement of curved subsections with different radii of curvature.

In some example embodiments, the lower section 108 of the casing 102 may be a substantially straight casing. Alternatively, the lower section 108 may include vertical undulations that enhance the typically segregated flow regime in the lower section 108. For example, undulations in the lower section 108 may enhance the standing wave effect of the segregated flow on the liquid that is layered between the gas and the inner surface of the lower section 108.

Although FIG. 1 illustrates the casing 102 in an offshore rig setup, in alternative embodiments, the casing 102 may be used in on-shore drilling or production operations without departing from the scope of this disclosure. For example, the seafloor 112 may instead be at a ground level. Further, in some alternative embodiments, the lower section 108 may be more or less slanted than shown in FIG. 1. In some alternative embodiments, the curved section 110 may have a shape other than shown in FIG. 1.

FIGS. 2A and 2B illustrate a portion 200 of the upper section 106 of the casing 102 shown in FIG. 1 before and after, respectively, curved subsections are formed in the upper section according to an example embodiment. As illustrated in FIG. 2A, the portion 200 of the upper section 106 of the casing 102 may have a substantially uniform inner diameter D_i. The inner diameter D_imay, for example, range between approximately 9.5 inches and 13.5 inches. Alternatively, the inner diameter D_imay be smaller than 9.5 inches or larger than 13.5 inches. Prior to the formation of the curved subsections 206, 208 shown in FIG. 2B, a vertical axis 202 extends through a center of the upper section 106. The vertical axis 202 may be used as a reference for the amount of deviation of the curved subsections 206, 208 as compared to the portion 200 shown in FIG. 2B.

As illustrated in FIG. 2B, a deviation d of a centerline 204 of the upper section 106 from the vertical axis 202 may represent a maximum deviation of the curved subsection 206, 208. To illustrate, the curved subsections 206, 208 may effectively reduce the inner diameter of the upper section 106 as shown in equation (3) below. To illustrate, at high velocities, the centrifugal effect resulting from gas flow through the curved subsections 206, 208 can cause accumulation of liquids and/or solids in the outer portions of the curved subsections 206, 208, which can result in constraining the flow of the high rate gas through the curved subsections 206, 208.

D_e=D_i−2d Equation (3)

In equation (3), D_erepresents the effective diameter of the upper section 106 as a result of the deviation d of the centerline 204 from the vertical axis 202, and D_iis the inner diameter of the upper section as shown in FIG. 2A and corresponds to the inner diameter of the upper section 106 in FIG. 2B with respect to a horizontal plane through the upper section 106.

In some example embodiments, the length L_ashown in FIG. 2B may represent a vertical length of the curved subsection 206, 208. For example, the length L_amay be approximately 1000 ft. Alternatively, the length L_amay be less or more than 1000 ft. As illustrated in FIG. 2B, the length L_amay correspond to an arc angle β with respect to a center C of a corresponding circle that includes the respective one of the curved subsections 206, 208. The vertical length L_aof each subsection 206, 208 is related to the radius of curvature R_cas shown in equation (4).

L_a=βR_c Equation (4)

In some example embodiments, the curved subsections 206, 208 may have substantially equal lengths. Alternatively, the curved subsections 206, 208 may have different lengths.

In some example embodiments, the radius of curvature R_cof each curved subsection 206, 208 may be sized to introduce a centrifugal effect at each curved subsection 206, 208. For example, the centrifugal effect at each curved subsection may be determined using equation (2). A segregated flow or a slug flow through the curved subsections 206, 208 of the upper section 106 may exhibit greater friction pressure drop than an annular mist flow at comparable flow rates. For example, a high flow rate (e.g., 1 bscf/day) through the curved subsections 206, 208 of the upper section 106 may result in centrifugal effects that push the liquid in a multiphase mixture flowing through the upper section 106 toward the inner wall of the upper section 106. Segregated flow resulting from the centrifugal effects may narrow the cross-sectional area of the upper section 106 that is open for gas flow. To illustrate, during the stratified flow regime resulting from the centrifugal effects, the gas and the liquid may flow through the upper section 106 of the casing 102 with the liquid being between the gas and the inner wall of the upper section 106. Because segregated flow and the slug flow typically exhibit greater pressure drop than annular mist flow, the centrifugal effect induced segregated or slug flow may allow use of fewer relief wells (e.g., a single relief well) than would otherwise be needed with a typical upper section of the casing 102 in order to successfully stop and control a blowout.

Different permutations of the number of curved subsections, radius of curvature Rc, and vertical lengths L_aof each subsection may be considered in determining the necessary centrifugal effects that result in segregated flow or slug flow. In some example embodiments, fewer curved subsections in the upper section 106 that have longer vertical lengths L_amay be preferable over more curved subsections that have shorter lengths L_a. In some example embodiments, fewer curved subsections in the upper section 106 that have larger radius of curvature R_cmay be preferable over more curved subsections that have smaller radius of curvature R_c.

Although two curved subsections discussed with respect to FIG. 2B, the upper section 106 may include more than two curved subsections. Alternatively, the upper section 106 may include just one curved subsection.

FIG. 3 illustrates a portion of the upper section 106 of the casing 102 of FIG. 1 as a spiral section according to another example embodiment. In some example embodiments, at least a portion 300 of the upper section 106 may have a spiral or helical shape. As illustrated in FIG. 3, a spiral section between lines 302 and 304 represents a single 360-degree rotation of the upper section 106. For example, the vertical length L of a spiral section between the lines 302 and 304 may be 1000 ft. Alternatively, the vertical length L may be shorter or longer than 1000 ft. In some example embodiments, at least the portion of 300 of upper section may have a corkscrew spiral shape.

The centrifugal effects that result from the flow of gas through the spiral sections of the upper section 106 depend on the spiral radius Rs of the curved section 110. In some example embodiments, the spiral sections of the upper section 106 may have spiral radii Rs that are substantially the same size for the entire length of the portion 300 of the upper section 106. Alternatively, the spiral sections of the upper section 106 that are closer to the curved section 110 shown in FIG. 1 may be have a larger radius Rs than spiral sections of the upper section 106 that are closer to the seafloor 112 shown in FIG. 1. In some example embodiments, the maximum spiral radius Rs of the spiral sections is limited by the diameter of the wellbore 104 and the diameters of the casing 102, particularly when the upper section of the wellbore does not have a spiral shape. For example, the wellbore 104 may be approximately 20 inches and the inner diameter of the casing 102 may be 13.5 inches.

As described above with respect to FIG. 2B, the centrifugal effects that result from the flow of gas through the spiral sections of the upper section 106 may result in a segregated flow or a slug flow through the upper section 106. Because segregated flow and the slug flow typically exhibit greater pressure drop than annular mist flow, the centrifugal effect induced segregated or slug flow may allow use of fewer relief wells (e.g., a single relief well) than would otherwise be needed with a typical upper section of the casing 102 in order to successfully stop and control a blowout. Further, less amount of kill fluid and/or lower pump rate of the kill fluid through a relief well may be required as a result of the centrifugal effects induced by the spiral sections of the casing 106.

In some example embodiments, the spiral sections may be formed in the upper section 106 of the casing 102 by drilling the wellbore 104 such that the upper section of the wellbore 104 has spiral sections that correspond to the desired spiral shape in the upper section 106. To illustrate, the upper section of the wellbore that has a spiral section(s) may first be drilled and followed by the rest of the wellbore including a curved section and a lower section of the wellbore. The casing 102 may then be inserted into the wellbore such that the casing 102 substantially conforms to the shape of the wellbore, where the upper section 106 of the casing 102 substantially conforms to the upper section of the wellbore that has spiral sections.

In some alternative embodiments, the spiral shape of at least a portion of the upper section 106 may be formed by using de-centralizers (not shown) to deviate portions of the upper section 106 from a vertical axis through a center of the wellbore 104. For example, centralizers (not shown) may be used to keep portions of the upper section 106 centralized within the wellbore 104, and one or more de-centralizers may be used between two centralizers to deviate from the vertical axis a portion of the upper section 106 that is between the two centralizers.

In some example embodiments, substantially the entire upper section 106 of the casing 102 may be a spiral shape. Alternatively, less than the entire upper section 106 may have a spiral shape.

FIG. 4 illustrates a portion 400 of the lower section 108 of the casing 102 of FIG. 1 that has undulations according to an example embodiment. As shown in FIG. 4, the lower section 108 of the casing 102 may include undulations 402, 404. The undulation 402 is between lines 406 and 408, and the undulation 404 is between the lines 408 and 410. For example, the undulations 402, 404 may correspond to a standing wave cycle. As illustrated in FIG. 4, a centerline 414 of the upper section 106 may be deviated from the center axis 412 of an equivalent lower section that does not include the undulations 402, 404.

As described above with respect to FIG. 1, the undulations 402, 404 may enhance the typically segregated flow regime in the lower section 108. For example, the undulations 402, 404 may enhance the standing wave effect of the segregated flow on the liquid that is layered between the gas and the inner surface of the lower section 108. In some example embodiments, the combined lengths of the undulations 402, 404 may add up to the wavelength of a standing wave that results from the typical segregated flow in a lower section 108 that does not have the undulations 402, 404.

Although some embodiments have been described herein in detail, the descriptions are by way of example. The features of the embodiments described herein are representative and, in alternative embodiments, certain features, elements, and/or steps may be added or omitted. Additionally, modifications to aspects of the embodiments described herein may be made by those skilled in the art without departing from the spirit and scope of the following claims, the scope of which are to be accorded the broadest interpretation so as to encompass modifications and equivalent structures.

Claims

1. A wellbore casing, comprising:

an upper section;

a curved section; and

a lower section, wherein the upper section extends down from a seafloor to the curved section, wherein the curved section is curved between the upper section and the lower section, wherein the lower section extends from the curved section toward a reservoir, and wherein the upper section includes multiple curved subsections.

2. The casing of claim 1, wherein a curvature of at least one curved subsection of the upper section corresponds to at least a 1-degree per 100 feet curvature.

3. The casing of claim 1, wherein a curvature of at least one curved subsection of the upper section corresponds to at least a 2-degrees per 100 feet curvature.

4. The casing of claim 1, wherein a curvature of at least one curved subsection of the upper section corresponds to at least a 6-degrees per 100 feet curvature.

5. The casing of claim 1, wherein at least one curved subsection of the upper section has a vertical length of approximately 1000 feet long.

6. The casing of claim 1, wherein the lower section includes vertical undulations.

7. The casing of claim 1, wherein the casing is disposed in a wellbore and wherein a curvature of at least one curved subsection of the upper section substantially matches a curvature of a curved section of the wellbore.

8. The casing of claim 1, wherein a maximum deviation of a center line of at least one curved subsection of the upper section from a vertical axis extending through a center of an equivalent straight subsection is at least approximately one fourth of an inner diameter of the casing.

9. The casing of claim 1, wherein radii of curvature of the curved subsections are large enough to allow a single relief well to stop a gas blowout through the casing.

10. The casing of claim 1, wherein the casing is disposed in a wellbore, wherein a curvature of at least one curved subsection of the upper section is formed by using a de-centralizer disposed outside of the casing within a wellbore to deviate a center of a portion of the casing from a vertical axis extending through a center of the wellbore.

11. The casing of claim 1, wherein a curvature of a first curved sub-section proximal to the curved section of the casing is larger than a curvature of a second curved sub-section that is distal from the curved section.

12. A wellbore casing, comprising:

an upper section including a spiral section;

a curved section; and

a lower section, wherein the upper section extends down from a seafloor to the curved section, wherein the curved section is curved between the upper section and the lower section, wherein the lower section extends from the curved section toward a reservoir, and wherein the upper section includes the spiral section.

13. The casing of claim 12, wherein the spiral section completes a 360-degree rotation in approximately 1000 feet vertical length.

14. The casing of claim 12, wherein a portion of the spiral section that is proximal to the curved section has a larger diameter than a portion of the spiral section that is proximal to the seafloor.

15. The casing of claim 12, wherein the spiral section has a radius of curvature that allows a single relief well to stop a blowout through the casing.

16. A method of drilling, the method comprising:

drilling an upper section of a wellbore;

drilling a curved section of the wellbore;

drilling a lower section of the wellbore, wherein the upper section of the wellbore extends down from a seafloor to the curved section of the wellbore, wherein the lower section of the wellbore extends from the curved section of the wellbore toward a reservoir, and wherein the upper section of the wellbore includes curved subsections of the wellbore; and

inserting a casing into the wellbore, wherein inserting the casing into the wellbore forms curved subsections of the casing in an upper section of the casing.

17. The method of claim 16, wherein the upper section of the wellbore has a corkscrew spiral portion that includes the curved subsections of the wellbore.

18. The method of claim 16, wherein inserting the casing into the wellbore forms a corkscrew spiral portion of the casing in the upper section of the casing and wherein the corkscrew spiral portion of the casing includes the curved subsections of the casing.