Optimal Subsurface Design for High Bubble Point Pressure Reservoirs

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.

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.

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.

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.

are schematic diagrams of an example multilateral well systemand/or well design, (hereinafter referred to as the “system”) that may employ one or more principles of the present disclosure. The systemmay include a service rigpositioned on a terranean surface. The service rigmay 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 rigis depicted as a wellhead arranged at the well surface. 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 rigand instead conducted with the well-intervention equipment deemed necessary by the well operator (rigless operations).

A wellboreextends below (from) the service rigand into a subsurface (subterranean) formation, which may include one or more hydrocarbon-bearing reservoirs. As depicted, the wellboreincludes a main or “primary” wellboreextending from the service rig, and one or more lateral wellbores (alternately referred to as “legs” or “secondary wellbores”), shown as lateral wellboresand, that extend from the primary wellbore. The primary wellboreand the lateral wellboresmay be configured to penetrate and ultimately produce the reservoir. The lateral wellbores(and a multilateral well design generally) may be beneficial during production, which increases contact with the reservoir, thereby increasing and, in some cases, maximizing production. It will be appreciated by those skilled in the art that even thoughdepict two lateral wellbores, the systemmay alternatively include more or less than two lateral wellbores, without departing from the scope of the disclosure.

According to embodiments of the present disclosure, the primary wellboremay include one or more tangent sections, shown as a first tangent sectionand a second tangent section. 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,may comprise a length and/or lengths corresponding to the size and length of an ESP to be disposed therein.

As illustrated, the primary wellboreextends from the service rigsubstantially verticalor in a substantially vertical direction, and the tangent sections,comprise corresponding portions of the primary wellborein which the trajectory of the primary wellboreis inclined from verticaland maintained (held constant) over corresponding predetermined distances/lengths. More specifically, the first tangent sectionfacilitates a first deviation from verticaland is positioned closer to the service rigand uphole from the second tangent section, and the second tangent sectionfacilitates a second deviation from verticaland extends from the first tangent section

The primary wellboreincludes a first build sectionwhere the trajectory of the primary wellborebuilds (deviates) in inclination (angle) away from verticaland transitions into the first tangent section. The first build sectionmay deviate to an angle greater than 0° but less than 55°. The first tangent sectionmay maintain the inclination achieved in the first build sectionfor a predetermined distance (length). The second tangent sectionextends from the first tangent sectionfollowing a second build section, where the inclination of the primary wellboredeviates from verticalto nearly horizontal. In some embodiments, for example, the second build sectionmay build to an inclination of approximately 70° to approximately 90° from vertical. Like the first tangent section, the second tangent sectionmay maintain the inclination achieved in the second build sectionfor a predetermined distance (length).

The primary wellboremay be lined with a string of casingextending from the surfaceand into the subsurface formation. Similarly, each lateral wellboreis lined with a corresponding linerandoperatively coupled to and extending from the casing. In other embodiments, the primary wellboreand the lateral wellboresmay 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, a string of production tubingmay be conveyed into the primary wellbore. In at least one embodiment, the distal end of the production tubingmay be operatively coupled to a completion stringat a matable interfacevia corresponding matable members (e.g., threaded engagement). The combination of the production tubingand the completion stringmay be conveyed into the primary wellboresuch that the production tubingextends beyond the first tangent section, through the second build sectionand into the second tangent section. The completion stringis thereby positioned below (downhole from) the second tangent sectionand within a generally horizontal portionof the primary wellbore.

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

In the embodiments illustrated in, the reservoirmay 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 wellboreat 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 surfacefor recovery and production.

In, the systemincludes an electrical submersible pump(hereinafter referred to as “ESP”) operable to assist in lifting (pumping) the recovered hydrocarbons to surface. The ESPmay be prearranged at a known location along the production tubingat surfaceso that when conveyed into and positioned in the primary wellbore, the ESPmay be oriented at an operationally desirable location. In determining the operationally desirable location of the ESP, the operator may consider the needs and requirements of both the reservoirand the primary wellboreas well as the overall health and life of the ESP, 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 ESPis particularly dependent upon the Pb and the PP of the reservoir. In, the reservoirmay exhibit a PP that is at or “near” (within +/−100 psi) the Pb. For this reason, it may be advantageous to position the ESPdeeper within the primary wellboreand as close as possible to the producible reservoir.

In, the production tubingmay be positioned within the primary wellboreso that the ESPis positioned (arranged, located) within the second tangent section. As illustrated, the second tangent sectionmay be deeper (in true vertical depth (TVD)) and in closer proximity to the producible reservoiras compared to the first tangent section. In this embodiment, positioning the ESPin the second tangent sectionhelps to maintain a higher pump intake pressure to the ESP. More specifically, positioning the ESPdeeper within the primary wellboreexposes the ESPto less pressure drop due to friction when positioned in the second tangent sectionrelative to other positions (e.g., higher up) within the production tubing. In some embodiments, positioning the ESPin the second tangentmay increase the pump intake pressure by ˜200 psi. Should the ESPincur 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, and inconsistency in the intake pressure to the ESPmay result in inadvertent shutdowns or “trips/tripping.” Events like “tripping” may shorten the life of the ESP.

Positioning the ESPat a depth optimized for consistent pump intake pressure results in ESPlongevity thereby avoiding the added cost and time associated with repairing or replacing the ESP. Additionally, positioning the ESPdeeper within the primary wellboremay maximize oil phase production and result in a high productivity index (PI).

In some embodiments, the ESPmay be powered by an electrical power supplylocated at the surfacethat enables the electrical components of the ESP(e.g., motor, sensors, etc.) to function. In one embodiment, the ESPmay 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. 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 controllermay be positioned on the surfaceand operatively coupled to the electrical power supply. The controller, configured to receive electricity from the electrical power supply, and may also include a variable speed drive (VSD). The controllermay be communicably coupled to the ESPvia a communication cableextending therebetween. The controllermay also be configured to generate commands (received from the operator) that are conveyed to the ESPvia the communication cable. In one embodiment, the controllermay transmit real-time commands to increase or decrease the speed of the downhole VSD to the ESP. The communication cablemay be extended into the service rigand through the interior of the production tubing, ultimately terminating at the ESP. 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 stringmay comprise a “smart” completion that includes one or more inflow control valves operable to control hydrocarbon flow through the system. In the example embodiment, the completion stringincludes three inflow control valves (ICVs),, andconfigurable and operable to regulate flow into the completion stringand partially or completely shut in a portion of the primary wellbore. In some embodiments, the ICVs-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-, trigger an automatic response. Example responses include complete closure, partial closure and complete opening of the ICVs-

The ICVs-enable optimized pressure control within the primary wellbore. The ICVs-may be selectively activated to prevent pressure loss within the systemas 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-may be actuated to induce pressure loss when operationally desirable. Accordingly, use of the ICVs-extends the producible life of the primary wellborewhere portions of the primary wellboremay be “shut-in” while maintaining the operability of the portions of the primary wellborethat still have adequate pressure. Consequently, use of the ICVs-extends the life of the ESP, because the ICVs-help to establish consistent pressure above Pb.

As illustrated in, the first ICVmay be arranged to regulate (e.g., prevent, partially or completely) hydrocarbon and/or water flow from the first lateral wellbore. The second ICVmay be arranged to regulate flow from the second lateral wellbore. Lastly, the third ICVmay be positioned to regulate flow from the distal end of the primary wellbore. In some embodiments, the ICVs-may be separated by one or more wellbore isolation devices, such as wellbore packers. As shown, the completion stringincludes three wellbore isolation devices-arranged within the completion stringand interposing the ICVs-. The wellbore isolation devices-may comprise any known element capable of generating a seal between an annulusdefined by the interior of the casingand the exterior of the completion string. The wellbore isolation devices-may be operable to prevent hydrocarbon flow between each respective ICV-, as operationally desired.

Referring now to, like the reservoirin, here again, the reservoirmay be undersaturated. However, in the embodiment illustrated inthe PP may no longer be considered “near” the Pb of the reservoir. More particularly, a larger pressure differential exists between the PP and the Pb inin comparison to the pressure differential between the PP and the Pb of the reservoirdepicted in.

Because the reservoirdepicted inexhibits a larger pressure differential between the PP and the Pb of the reservoir, the ESPmay be positioned shallower relative to its position in. Consequently, the production tubingmay be extended into the primary wellboreso that the ESPis positioned within the first tangent section, where the first tangent sectionis shallower (in true vertical depth (TVD)) and farther from the producible reservoiras compared to the second tangent section. 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) it is unlikely that the ESPwill experience gas breakout. Similarly, the intake pressure to the ESPis less likely to fall below the Pb, making the ESPless susceptible to tripping and premature failure. Additionally, the production capability of the reservoirmay be maintained because the PP is still greater than Pb (undersaturated reservoir).

Like the systemillustrated in, the completion stringinmay remain operatively coupled to, and extend below, the distal end of the production tubingat the matable interface. However, given the position of the ESPin the first tangent section, a portion of the completion stringextends through the second build sectionand terminates in the generally horizontal portionof the primary wellbore.

Accordingly, the systemdisclosed herein provides the operator with flexibility in ESPplacement and optimization capabilities via the multilateral wellboresand ICVs-. Throughout the life of the primary wellbore, the operator may change the placement of the ESPbased upon the considerations of the reservoirand the wellbore(s),thereby potentially maximizing the production capabilities of the reservoir.

is a schematic flowchart of an example methodof optimizing a well design, including an electrical submersible pump (ESP), according to the principles of the present disclosure. The methodmay 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. 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 methodmay 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. Alternatively, the methodmay 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. 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:

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.