OPTIMAL SUBSURFACE DESIGN FOR HIGH BUBBLE POINT PRESSURE RESERVOIRS

Abstract

A well system includes a primary wellbore extending vertical from a service rig and penetrating a subterranean formation including a hydrocarbon-bearing, undersaturated reservoir. The primary wellbore includes a first tangent section extending at a first inclination from vertical and a second tangent section extending from the first tangent section and at a second inclination from vertical. The well system includes an electrical submersible pump (ESP) positioned in the first tangent section or the second tangent section based on a bubble point pressure of the hydrocarbon-bearing reservoir.

Description

FIELD OF THE DISCLOSURE

The present disclosure relates generally to oil production from reservoirs with high bubble point pressures and, more particularly, to an optimized multi-lateral well design including an electrical submersible pump.

BACKGROUND OF THE DISCLOSURE

To maximize hydrocarbon recovery, subterranean hydrocarbon-bearing reservoirs are ideally produced at pressures that are above the bubble point pressure of the oil solution immersed within said reservoirs. Recovery above bubble point enables single-phase oil production which is advantageous in both cost and time. In reservoirs where the bubble point pressure is at or near the pressure of the reservoir, the well design (including equipment requirements) is critical in maintaining a production pressure that stays above bubble point.

Hydrocarbon producing wells include configurations of permanent and semi-permanent equipment that may be installed during well construction to maintain or increase production over the life of the well. An electric submersible pump (ESP) and associated components are one such type of semi-permanent (or permanent) equipment that is often utilized to assist in artificially lifting (pumping) hydrocarbons to the well surface for production. Non-optimized placement of an ESP may inadvertently induce a larger pressure drop which can result in production pressure falling below bubble point.

The well design and methods disclosed herein provide an effective and flexible solution to optimizing and maintaining a producing pressure that is greater than bubble point pressure.

SUMMARY OF THE DISCLOSURE

Various details of the present disclosure are hereinafter summarized to provide a basic understanding. This summary is not an exhaustive overview of the disclosure and is neither intended to identify certain elements of the disclosure, nor to delineate the scope thereof. Rather, the primary purpose of this summary is to present some concepts of the disclosure in a simplified form prior to the more detailed description that is presented hereinafter.

According to an embodiment consistent with the present disclosure, a well system may include a primary wellbore extending vertical from a service rig and penetrating a subterranean formation including a hydrocarbon-bearing, undersaturated reservoir. The primary wellbore may include a first tangent section extending at a first inclination from vertical and a second tangent section extending from the first tangent section and at a second inclination from vertical. The well system may also include an electrical submersible pump (ESP) positioned in the first tangent section or the second tangent section based on a bubble point pressure of the hydrocarbon-bearing reservoir.

According to an embodiment consistent with the present disclosure, a method may include conveying an electrical submersible pump (ESP) into a primary wellbore extending vertical from a service rig and penetrating a subterranean formation including a hydrocarbon-bearing undersaturated reservoir. The primary wellbore may include a first tangent section extending at a first inclination from vertical and a second tangent section extending from the first tangent section and at a second inclination from vertical. The method may include positioning the ESP within the second tangent section when a pore pressure of the reservoir is at or within 100 psi of a bubble point pressure of the reservoir and positioning the ESP within the first tangent section when a pore pressure of the reservoir exceeds a bubble point pressure of the reservoir by at least 200 psi.

According to an embodiment consistent with the present disclosure, a well system may include a primary wellbore extending vertical from a service rig and penetrating a subterranean formation including a hydrocarbon-bearing, undersaturated reservoir. The primary wellbore may include a first tangent section extending at a first inclination from vertical and a second tangent section extending from the first tangent section and at a second inclination from vertical. The well system may also include one or more lateral wellbores extending from the primary wellbore and a completion string including one or more inflow control valves positioned adjacent the one or more lateral wellbores and operable to regulate hydrocarbon flow. The well system may include an electrical submersible pump (ESP) positioned in the primary wellbore based on a bubble point pressure of the hydrocarbon-bearing reservoir.

Any combinations of the various embodiments and implementations disclosed herein can be used in a further embodiment, consistent with the disclosure. These and other aspects and features can be appreciated from the following description of certain embodiments presented herein in accordance with the disclosure and the accompanying drawings and claims.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1A is a schematic diagram of an example multilateral wellbore system disposed within an undersaturated reservoir under certain pressure conditions that may employ one or more principles of the present disclosure.

FIG. 1B is a schematic diagram of the example multilateral wellbore system depicted in FIG. 1A, disposed within an undersaturated reservoir under certain pressure conditions that differ from those in FIG. 1A and that may employ one or more principles of the present disclosure.

FIG. 2 is a schematic flowchart of an example method of optimizing a well design, including an electrical submersible pump (ESP), according to the principles of the present disclosure.

DETAILED DESCRIPTION

Embodiments of the present disclosure will now be described in detail with reference to the accompanying Figures. Like elements in the various figures may be denoted by like reference numerals for consistency. Further, in the following detailed description of embodiments of the present disclosure, numerous specific details are set forth in order to provide a more thorough understanding of the claimed subject matter. However, it will be apparent to one of ordinary skill in the art that the embodiments disclosed herein may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description. Additionally, it will be apparent to one of ordinary skill in the art that the scale of the elements presented in the accompanying Figures may vary without departing from the scope of the present disclosure.

Embodiments in accordance with the present disclosure relate generally to oil production from reservoirs with high bubble point pressures and, more particularly, to an optimized multilateral well design including one or more electrical submersible pumps. It is highly advantageous to produce a hydrocarbon producible reservoir at a pressure that is greater than the bubble point pressure of the reservoir. Doing so allows the well(s) penetrating the reservoir to produce hydrocarbons in a single, liquid phase, thereby reducing the cost and time of the post-hydrocarbon recovery phase. The well designs discussed herein utilize an electrical submersible pump (ESP) optimally positioned to minimize pressure loss and free gas when the reservoir is produced at its optimal rate. The well designs incorporate both high angle deviations and tangent sections to enable placement flexibility of the ESP. The well designs further comprise a multilateral wellbore configuration, which helps to manage the reservoir pressure drop as the well is produced while also maximizing production productivity. The well designs described herein may also include a completion system, which may include one or more inflow control valves (ICV) operable to manage the hydrocarbon productivity and water cut ratio in each leg of the wellbore. Lastly, the well designs described herein are applicable for tight reservoirs where permeability is minimal or non-existent.

FIGS. 1A and 1B are schematic diagrams of an example multilateral well system 100 and/or well design 100, (hereinafter referred to as the “system 100”) that may employ one or more principles of the present disclosure. The system 100 may include a service rig 102 positioned on a terranean surface 104. The service rig 102 may include but is not limited to a wellhead, a completion rig, a workover rig, a drilling rig or any combination thereof. In the illustrated embodiment, the service rig 102 is depicted as a wellhead arranged at the well surface 104. It will be appreciated by those skilled in the art, however, that the various embodiments discussed herein are equally well suited for use in conjunction with other types of oil and gas platforms or rigs, such as offshore positioned oil and gas rigs or rigs located at any other geographical site. In the alternative, the embodiments and operations disclosed herein may be carried out without use of a service rig 102 and instead conducted with the well-intervention equipment deemed necessary by the well operator (rigless operations).

A wellbore 105 extends below (from) the service rig 102 and into a subsurface (subterranean) formation 106, which may include one or more hydrocarbon-bearing reservoirs 109. As depicted, the wellbore 105 includes a main or “primary” wellbore 108 extending from the service rig 102, and one or more lateral wellbores (alternately referred to as “legs” or “secondary wellbores”), shown as lateral wellbores 110a and 110b, that extend from the primary wellbore 108. The primary wellbore 108 and the lateral wellbores 110a,b may be configured to penetrate and ultimately produce the reservoir 109. The lateral wellbores 110a,b (and a multilateral well design generally) may be beneficial during production, which increases contact with the reservoir 109, thereby increasing and, in some cases, maximizing production. It will be appreciated by those skilled in the art that even though FIGS. 1A-1B depict two lateral wellbores 110a,b, the system 100 may alternatively include more or less than two lateral wellbores 110a,b, without departing from the scope of the disclosure.

According to embodiments of the present disclosure, the primary wellbore 108 may include one or more tangent sections, shown as a first tangent section 112a and a second tangent section 112b. The term “tangent,” refers to a known distance or length of a wellbore in which the inclination (deviation) from vertical remains constant within a small variance in angle. The term “tangent” also refers to the potential setting location of an ESP. Accordingly, in some embodiments, the tangent sections 112a, 112b may comprise a length and/or lengths corresponding to the size and length of an ESP to be disposed therein.

As illustrated, the primary wellbore 108 extends from the service rig 102 substantially vertical 111 or in a substantially vertical direction, and the tangent sections 112a, 112b comprise corresponding portions of the primary wellbore 108 in which the trajectory of the primary wellbore 108 is inclined from vertical 111 and maintained (held constant) over corresponding predetermined distances/lengths. More specifically, the first tangent section 112a facilitates a first deviation from vertical 111 and is positioned closer to the service rig 102 and uphole from the second tangent section 112b, and the second tangent section 112b facilitates a second deviation from vertical 111 and extends from the first tangent section 112a.

The primary wellbore 108 includes a first build section 113 where the trajectory of the primary wellbore 108 builds (deviates) in inclination (angle) away from vertical 111 and transitions into the first tangent section 112a. The first build section 113 may deviate to an angle greater than 0° but less than 55°. The first tangent section 112a may maintain the inclination achieved in the first build section 113 for a predetermined distance (length). The second tangent section 112b extends from the first tangent section 112a following a second build section 115, where the inclination of the primary wellbore 108 deviates from vertical 111 to nearly horizontal. In some embodiments, for example, the second build section 115 may build to an inclination of approximately 70° to approximately 90° from vertical 111. Like the first tangent section 112a, the second tangent section 112b may maintain the inclination achieved in the second build section 115 for a predetermined distance (length).

The primary wellbore 108 may be lined with a string of casing 114 extending from the surface 104 and into the subsurface formation 106. Similarly, each lateral wellbore 110a,b is lined with a corresponding liner 116a and 116b operatively coupled to and extending from the casing 114. In other embodiments, the primary wellbore 108 and the lateral wellbores 110a,b may be lined with any configuration of casing and/or liners, that may be operationally desirable and/or necessary.

In preparation to complete and ultimately produce the reservoir 109, a string of production tubing 118 may be conveyed into the primary wellbore 108. In at least one embodiment, the distal end of the production tubing 118 may be operatively coupled to a completion string 119 at a matable interface 117 via corresponding matable members (e.g., threaded engagement). The combination of the production tubing 118 and the completion string 119 may be conveyed into the primary wellbore 108 such that the production tubing 118 extends beyond the first tangent section 112a, through the second build section 115 and into the second tangent section 112b. The completion string 119 is thereby positioned below (downhole from) the second tangent section 112b and within a generally horizontal portion 120 of the primary wellbore 108.

In some embodiments, the reservoir 109 may be considered “undersaturated,” meaning that the pressure/pore pressure (“PP”) of the reservoir 109 is greater than the bubble point pressure (“Pb”) of the oil immersed within the reservoir 109. The Pb is the pressure at which natural gas begins to come out of solution to form gas bubbles. In other embodiments, the reservoir 109 may be deemed “saturated,” wherein the PP is less than the bubble point pressure (“Pb”) of the oil immersed within.

In the embodiments illustrated in FIGS. 1A-B, the reservoir 109 may be undersaturated and comprise a Pb that may be considered “high,” wherein a high Pb may comprise a pressure that is within 5 psi to 50 psi of the PP.

It is advantageous to produce the primary wellbore 108 at a pressure that exceeds the Pb, since production above Pb results in single, liquid hydrocarbon phase (oil) recovery. Single phase recovery is less costly in both time and money relative to two-phase (oil and gas) production operations due to the additional time and equipment needed for separation, or otherwise, in two-phase hydrocarbon recovery. In addition, production above Pb helps to maximize ultimate recovery of the reserves because a production pressure that exceeds the Pb prevents the formation of a secondary gas cap.

Producible wellbores are often constructed to include downhole equipment that may be utilized to either increase the initial hydrocarbon production rate, or similarly, to facilitate future hydrocarbon production when the reservoir begins to deplete over time. Electrical submersible pump (ESP) systems are commonly utilized for this purpose, wherein a downhole motor powered by surface sourced electricity powers a downhole pump which ultimately acts to pressurize and artificially “lift” hydrocarbons to the well surface 104 for recovery and production.

In FIG. 1A, the system 100 includes an electrical submersible pump 122 (hereinafter referred to as “ESP 122”) operable to assist in lifting (pumping) the recovered hydrocarbons to surface 104. The ESP 122 may be prearranged at a known location along the production tubing 118 at surface 104 so that when conveyed into and positioned in the primary wellbore 108, the ESP 122 may be oriented at an operationally desirable location. In determining the operationally desirable location of the ESP 122, the operator may consider the needs and requirements of both the reservoir 109 and the primary wellbore 108 as well as the overall health and life of the ESP 122, itself. Generally, considerations may include but are not limited to the location of perforations (if present), reservoir pressure/pore pressure (PP) and reservoir depth.

According to embodiments of the present disclosure, placement of the ESP 122 is particularly dependent upon the Pb and the PP of the reservoir 109. In FIG. 1A, the reservoir 109 may exhibit a PP that is at or “near” (within +/−100 psi) the Pb. For this reason, it may be advantageous to position the ESP 122 deeper within the primary wellbore 108 and as close as possible to the producible reservoir 109.

In FIG. 1A, the production tubing 118 may be positioned within the primary wellbore 108 so that the ESP 122 is positioned (arranged, located) within the second tangent section 112b. As illustrated, the second tangent section 112b may be deeper (in true vertical depth (TVD)) and in closer proximity to the producible reservoir 109 as compared to the first tangent section 112a. In this embodiment, positioning the ESP 122 in the second tangent section 112b helps to maintain a higher pump intake pressure to the ESP 122. More specifically, positioning the ESP 122 deeper within the primary wellbore 108 exposes the ESP 122 to less pressure drop due to friction when positioned in the second tangent section 112b relative to other positions (e.g., higher up) within the production tubing 118. In some embodiments, positioning the ESP 122 in the second tangent 112b may increase the pump intake pressure by ˜200 psi. Should the ESP 122 incur an intake pressure that drops below the Pb, gas breakout is likely to occur, the result of which may be costly, two-phase recovery. Additionally, gas breakout disturbs a consistent intake pressure to the ESP 122, and inconsistency in the intake pressure to the ESP 122 may result in inadvertent shutdowns or “trips/tripping.” Events like “tripping” may shorten the life of the ESP 122.

Positioning the ESP 122 at a depth optimized for consistent pump intake pressure results in ESP 122 longevity thereby avoiding the added cost and time associated with repairing or replacing the ESP 122. Additionally, positioning the ESP 122 deeper within the primary wellbore 108 may maximize oil phase production and result in a high productivity index (PI).

In some embodiments, the ESP 122 may be powered by an electrical power supply 123 located at the surface 104 that enables the electrical components of the ESP 122 (e.g., motor, sensors, etc.) to function. In one embodiment, the ESP 122 may include a downhole variable speed drive (VSD) motor configurable to operate at varying speeds (RPM). In such an embodiment, the downhole VSD may be programmed to operate at speeds that assist in maintaining the produced fluid pressure at a pressure above the Pb of the reservoir 109. For example, the downhole VSD may be programmed to adjust its speed should the pump intake pressure come within a predetermined pressure range of the Pb (e.g., 100 psi above Pb).

A controller 126 may be positioned on the surface 104 and operatively coupled to the electrical power supply 123. The controller 126, configured to receive electricity from the electrical power supply 123, and may also include a variable speed drive (VSD). The controller 126 may be communicably coupled to the ESP 122 via a communication cable 124 extending therebetween. The controller 126 may also be configured to generate commands (received from the operator) that are conveyed to the ESP 122 via the communication cable 124. In one embodiment, the controller 126 may transmit real-time commands to increase or decrease the speed of the downhole VSD to the ESP 122. The communication cable 124 may be extended into the service rig 102 and through the interior of the production tubing 118, ultimately terminating at the ESP 122. As used herein, the term “operatively coupled,” and any variations thereof, refers to a direct or indirect coupling between two component parts.

In some embodiments, the completion string 119 may comprise a “smart” completion that includes one or more inflow control valves operable to control hydrocarbon flow through the system 100. In the example embodiment, the completion string 119 includes three inflow control valves (ICVs) 128a, 128b, and 128c configurable and operable to regulate flow into the completion string 110 and partially or completely shut in a portion of the primary wellbore 108. In some embodiments, the ICVs 128a-c may be programmable and otherwise configurable with threshold values (e.g., pressure, temperature, flow rate, water production rate, etc.), that once recognized by the ICVs 128a-c, trigger an automatic response. Example responses include complete closure, partial closure and complete opening of the ICVs 128a-c.

The ICVs 128a-c enable optimized pressure control within the primary wellbore 108. The ICVs 128a-c may be selectively activated to prevent pressure loss within the system 100 as well as to maintain a desirable water cut ratio (i.e., the ratio of water produced in comparison to the total liquids produced from a wellbore). In the alternative, the ICVs 128a-c may be actuated to induce pressure loss when operationally desirable. Accordingly, use of the ICVs 128a-c extends the producible life of the primary wellbore 108 where portions of the primary wellbore 108 may be “shut-in” while maintaining the operability of the portions of the primary wellbore 108 that still have adequate pressure. Consequently, use of the ICVs 128a-c extends the life of the ESP 122, because the ICVs 128a-c help to establish consistent pressure above Pb.

As illustrated in FIG. 1A, the first ICV 128a may be arranged to regulate (e.g., prevent, partially or completely) hydrocarbon and/or water flow from the first lateral wellbore 110a. The second ICV 128b may be arranged to regulate flow from the second lateral wellbore 110b. Lastly, the third ICV 128c may be positioned to regulate flow from the distal end of the primary wellbore 108. In some embodiments, the ICVs 128a-c may be separated by one or more wellbore isolation devices 130, such as wellbore packers. As shown, the completion string 119 includes three wellbore isolation devices 130a-c arranged within the completion string 119 and interposing the ICVs 128a-c. The wellbore isolation devices 130a-c may comprise any known element capable of generating a seal between an annulus 132 defined by the interior of the casing 114 and the exterior of the completion string 119. The wellbore isolation devices 130a-c may be operable to prevent hydrocarbon flow between each respective ICV 128a-c, as operationally desired.

Referring now to FIG. 1B, like the reservoir 109 in FIG. 1A, here again, the reservoir 109 may be undersaturated. However, in the embodiment illustrated in FIG. 1B the PP may no longer be considered “near” the Pb of the reservoir 109. More particularly, a larger pressure differential exists between the PP and the Pb in FIG. 1B in comparison to the pressure differential between the PP and the Pb of the reservoir 109 depicted in FIG. 1A.

Because the reservoir 109 depicted in FIG. 1B exhibits a larger pressure differential between the PP and the Pb of the reservoir 109, the ESP 122 may be positioned shallower relative to its position in FIG. 1A. Consequently, the production tubing 118 may be extended into the primary wellbore 108 so that the ESP 122 is positioned within the first tangent section 112a, where the first tangent section 112a is shallower (in true vertical depth (TVD)) and farther from the producible reservoir 109 as compared to the second tangent section 112b. In this example, despite a higher-pressure loss due to friction (because of the greater differential between the Pb and the PP of the reservoir 109) it is unlikely that the ESP 122 will experience gas breakout. Similarly, the intake pressure to the ESP 122 is less likely to fall below the Pb, making the ESP 122 less susceptible to tripping and premature failure. Additionally, the production capability of the reservoir 109 may be maintained because the PP is still greater than Pb (undersaturated reservoir) 109.

Like the system 100 illustrated in FIG. 1A, the completion string 119 in FIG. 1B may remain operatively coupled to, and extend below, the distal end of the production tubing 118 at the matable interface 117. However, given the position of the ESP 122 in the first tangent section 112a, a portion of the completion string 119 extends through the second build section 115 and terminates in the generally horizontal portion 120 of the primary wellbore 108.

Accordingly, the system 100 disclosed herein provides the operator with flexibility in ESP 122 placement and optimization capabilities via the multilateral wellbores 110a,b and ICVs 130a-c. Throughout the life of the primary wellbore 108, the operator may change the placement of the ESP 122 based upon the considerations of the reservoir 109 and the wellbore(s) 106, 110a,b thereby potentially maximizing the production capabilities of the reservoir 109.

FIG. 2 is a schematic flowchart of an example method 200 of optimizing a well design, including an electrical submersible pump (ESP), according to the principles of the present disclosure. The method 200 may include conveying an electrical submersible pump (ESP) into a primary wellbore extending vertical from a service rig and penetrating a subterranean formation including a hydrocarbon-bearing, undersaturated reservoir, as at 202. In some embodiments, the reservoir may comprise a reservoir pressure/pore pressure that is at or “near” (within ˜+/−100 psi) the bubble point pressure of the reservoir. Alternatively, the reservoir may comprise a reservoir pressure/pore pressure (“PP”) that is more than ˜100 psi above the bubble point pressure (“Pb”) of the reservoir. The primary wellbore may include a first tangent section extending at a first inclination from vertical and a second tangent section extending at a second inclination from vertical, wherein the second tangent extends from the first tangent and said second tangent is positioned downhole from the first tangent section. The method 200 may include positioning the ESP within the second tangent section when the PP of the reservoir is at or near the Pb of the reservoir, as at 204. Alternatively, the method 200 may include positioning the ESP within the first tangent section when the PP of the reservoir is more than 100 psi greater than the Pb of the reservoir, as at 206. As the wellbore is produced, the ESP may be repositioned within the first and second tangents based upon the changing pressure conditions of the reservoir.

Embodiments disclosed herein include:

• • A. A well system, including a primary wellbore extending vertical from a service rig and penetrating a subterranean formation including a hydrocarbon-bearing, undersaturated reservoir. The primary wellbore including a first tangent section extending at a first inclination from vertical and a second tangent section extending from the first tangent section and at a second inclination from vertical. The well system including an electrical submersible pump (ESP) positioned in the first tangent section or the second tangent section based on a bubble point pressure of the hydrocarbon-bearing reservoir.
  • B. A method, including conveying an electrical submersible pump (ESP) into a primary wellbore extending vertical from a service rig and penetrating a subterranean formation including a hydrocarbon-bearing, undersaturated reservoir, the primary wellbore including a first tangent section extending at a first inclination from vertical and a second tangent section extending from the first tangent section and at a second inclination from vertical. The method including positioning the ESP within the second tangent section when a pore pressure of the reservoir is at or within 100 psi of a bubble point pressure of the reservoir and positioning the ESP within the first tangent section when a pore pressure of the reservoir exceeds a bubble point pressure of the reservoir by at least 200 psi.
  • C. A well system, including a primary wellbore extending vertical from a service rig and penetrating a subterranean formation including a hydrocarbon-bearing, undersaturated reservoir, the primary wellbore including a first tangent section extending at a first inclination from vertical and a second tangent section extending from the first tangent section and at a second inclination from vertical. The well system including one or more lateral wellbores extending from the primary wellbore, a completion string including one or more inflow control valves positioned adjacent the one or more lateral wellbores and operable to regulate hydrocarbon flow and an electrical submersible pump (ESP) positioned in the primary wellbore based on a bubble point pressure of the hydrocarbon-bearing reservoir.

Each of embodiments A, B, and C may have one or more of the following additional elements in any combination: Element 1: wherein the ESP is positioned in the second tangent section when a pore pressure of the reservoir is within 100 psi of a bubble point pressure of the reservoir. Element 2: wherein the ESP is positioned in the first tangent section when a pore pressure of the reservoir exceeds a bubble point pressure of the reservoir by at least 200 psi. Element 3: wherein the primary wellbore further includes a first build section extending from vertical to the first tangent section, the first build section transitioning the primary wellbore from vertical to the first inclination and a second build section extending from the first tangent section and transitioning the primary wellbore from the first inclination to the second inclination. Element 4: wherein the first inclination ranges between 1° and 55°. Element 5: wherein the second inclination ranges between 70° and 90°. Element 6: wherein the ESP is operatively coupled to production tubing extended into the primary wellbore, the well system further includes one or more lateral wellbores extending from the primary wellbore and a completion string extending from the production tubing and including one or more inflow control valves positioned adjacent the one or more lateral wellbores and operable to regulate hydrocarbon flow into the production tubing. Element 7: further comprising a controller and a variable speed drive positioned at the service rig and operable to control operation of the ESP. Element 8: wherein the variable speed drive is programmed to maintain a predetermined pump intake pressure. Element 9: wherein the predetermined pump intake pressure is set to 100 psi above the bubble point pressure of the reservoir.

Element 10: wherein the primary wellbore further includes a first build section extending from vertical to the first tangent section, the first build section transitioning the primary wellbore from vertical to the first inclination and a second build section extending from the first tangent section and transitioning the primary wellbore from the first inclination to the second inclination. Element 11: wherein the first inclination from surface ranges between 1° and 55°. Element 12: wherein the second inclination ranges between 70° and 90°. Element 13: wherein the primary wellbore further includes one or more lateral wellbores extending from the primary wellbore, the method further includes conveying a completion string into the wellbore, the completion string being located downhole from the ESP, positioning one or more inflow control valves included in the completion string adjacent the one or more lateral wellbores and regulating hydrocarbon flow into the completion string from the one or more inflow control valves. Element 14: further comprising controlling operation of the ESP with a controller and a variable speed drive positioned at the service rig. Element 15: further including setting the variable speed drive to a predetermined pump intake pressure and adjusting a speed of the variable speed drive when the predetermined pump intake pressure is achieved.

Element 16: wherein the primary wellbore includes a first tangent section extending at a first inclination from vertical and a second tangent section extending from the first tangent section and at a second inclination from vertical. Element 17: wherein the ESP is positioned in the first tangent section or the second tangent section based on a bubble point pressure of the hydrocarbon-bearing reservoir.

By way of non-limiting example, exemplary combinations applicable to A through C include: Element 8 with Element 9; Element 14 with Element 15; and Element 16 with Element 17.

The terminology used herein is for the purpose of describing particular embodiments only and is not intended to be limiting of the invention. As used herein, for example, the singular forms “a,” “an,” and “the” are intended to include the plural forms as well, unless the context clearly indicates otherwise. It will be further understood that the terms “contains”, “containing”, “includes”, “including,” “comprises”, and/or “comprising,” and variations thereof, when used in this specification, specify the presence of stated features, integers, steps, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, integers, steps, operations, elements, components, and/or groups thereof.

Terms of orientation used herein are merely for purposes of convention and referencing and are not to be construed as limiting. However, it is recognized these terms could be used with reference to an operator or user. Accordingly, no limitations are implied or to be inferred. In addition, the use of ordinal numbers (e.g., first, second, third, etc.) is for distinction and not counting. For example, the use of “third” does not imply there must be a corresponding “first” or “second.” Also, if used herein, the terms “coupled” or “coupled to” or “connected” or “connected to” or “attached” or “attached to” may indicate establishing either a direct or indirect connection, and is not limited to either unless expressly referenced as such.

While the disclosure has described several exemplary embodiments, it will be understood by those skilled in the art that various changes can be made, and equivalents can be substituted for elements thereof, without departing from the spirit and scope of the invention. In addition, many modifications will be appreciated by those skilled in the art to adapt a particular instrument, situation, or material to embodiments of the disclosure without departing from the essential scope thereof. Therefore, it is intended that the invention not be limited to the particular embodiments disclosed, or to the best mode contemplated for carrying out this invention, but that the invention will include all embodiments falling within the scope of the appended claims. Moreover, reference in the appended claims to an apparatus or system or a component of an apparatus or system being adapted to, arranged to, capable of, configured to, enabled to, operable to, or operative to perform a particular function encompasses that apparatus, system, or component, whether or not it or that particular function is activated, turned on, or unlocked, as long as that apparatus, system, or component is so adapted, arranged, capable, configured, enabled, operable, or operative.

Claims

1.-10. (canceled)

11. A method, comprising:

conveying an electrical submersible pump (ESP) into a primary wellbore extending vertical from a service rig and penetrating a subterranean formation including a hydrocarbon-bearing, undersaturated reservoir, the primary wellbore including: a first tangent section extending at a first inclination from vertical; and a second tangent section extending from the first tangent section and at a second inclination from vertical;

positioning the ESP within the second tangent section when a pore pressure of the reservoir is at or within 100 psi of a bubble point pressure of the reservoir; and

positioning the ESP within the first tangent section when the pore pressure of the reservoir exceeds the bubble point pressure of the reservoir by at least 200 psi.

12. The method of claim 11, wherein the primary wellbore further includes:

a first build section extending from vertical to the first tangent section, the first build section transitioning the primary wellbore from vertical to the first inclination; and

a second build section extending from the first tangent section and transitioning the primary wellbore from the first inclination to the second inclination.

13. The method of claim 11, wherein the first inclination from surface ranges between 1° and 55° from vertical.

14. The method claim 11, wherein the second inclination ranges between 70° and 90° from vertical.

15. The method of claim 11, wherein the primary wellbore further includes one or more lateral wellbores extending from the primary wellbore, the method further comprising:

conveying a completion string into the wellbore, the completion string being located downhole from the ESP;

positioning one or more inflow control valves included in the completion string adjacent the one or more lateral wellbores; and

regulating hydrocarbon flow into the completion string from the one or more inflow control valves.

16. The method of claim 11, further comprising controlling operation of the ESP with a controller and a variable speed drive positioned at the service rig.

17. The method of claim 16, further comprising:

setting the variable speed drive to a predetermined pump intake pressure; and adjusting a speed of the variable speed drive when the predetermined pump intake pressure is achieved.

18. A well system, comprising:

a primary wellbore extending vertical from a service rig and penetrating a subterranean formation including a hydrocarbon-bearing, undersaturated reservoir, the primary wellbore including: a first tangent section extending at a first inclination from vertical; and a second tangent section extending from the first tangent section and at a second inclination from vertical;

one or more lateral wellbores extending from the primary wellbore;

a completion string including one or more inflow control valves positioned adjacent the one or more lateral wellbores and operable to regulate hydrocarbon flow; and

an electrical submersible pump (ESP) positioned in the primary wellbore based on a bubble point pressure of the hydrocarbon-bearing reservoir, wherein the ESP is positioned within the first tangent section when a pore pressure of the reservoir exceeds the bubble point pressure of the reservoir by at least 200 psi and positioned within the second tangent section when the pore pressure of the reservoir is at or within 100 psi of the bubble point pressure of the reservoir.

19. (canceled)

20. (canceled)

21. The well system of claim 18, the completion string further comprising:

a first wellbore isolation device and a second wellbore isolation device straddling a lateral wellbore of the one or more lateral wellbores and sealing against a surface of the primary wellbore, the first and second wellbore isolation devices being downhole from the ESP; and

the one or more inflow control valves including an inflow control valve interposing the first and second wellbore isolation devices,

wherein the completion string is attached to a production tubing including the ESP at a matable interface.

22. The well system of claim 18, wherein the primary wellbore further includes:

a first build section extending from vertical to the first tangent section, the first build section transitioning the primary wellbore from vertical to the first inclination; and

a second build section extending from the first tangent section and transitioning the primary wellbore from the first inclination to the second inclination.

23. The well system of claim 18, wherein the first inclination ranges between 1° and 55° from vertical.

24. The well system of claim 18, wherein the second inclination ranges between 70° and 90° from vertical.

25. The well system of claim 18, wherein the ESP is operatively coupled to production tubing extended into the primary wellbore, the well system further comprising:

one or more lateral wellbores extending from the primary wellbore; and

a completion string extending from the production tubing and including one or more inflow control valves positioned adjacent the one or more lateral wellbores and operable to regulate hydrocarbon flow into the production tubing.

26. The well system of claim 18, further comprising a controller and a variable speed drive positioned at the service rig and operable to control operation of the ESP.

27. The well system of claim 26, wherein the variable speed drive is programmed to maintain a predetermined pump intake pressure.

28. The well system of claim 27, wherein the predetermined pump intake pressure is set to 100 psi above the bubble point pressure of the reservoir.

29. The method of claim 15, wherein the completion string includes a pair of wellbore isolation devices straddling each inflow control valve, wherein each wellbore isolation device seals against a surface of the primary wellbore.

30. The method of claim 29, wherein the completion string is attached to a production tubing that includes the ESP at a matable interface.