Cold Heavy Oil Production System and Methods

Abstract

A system for producing hydrocarbons and sand from a formation includes a wellbore having a substantially horizontal portion. In addition, the system includes a liner disposed in the substantially horizontal portion. The liner has a longitudinal axis and includes a plurality of slots. Each slot is configured to pass sand from the formation into the wellbore. Further, the system includes a production string extending through the wellbore. Still further, the system includes a pump disposed at a downhole end of the production string in the liner. The pump has a central axis, an outlet coupled to the downhole end of the production tubing, and an inlet distal the production string. The pump is configured to pump hydrocarbons and sand from the formation to the surface. The central axis of the pump is oriented at an angle α measured downward from vertical. The angle α is between 60° and 90°.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims benefit of U.S. provisional patent application Ser. No. 61/624,053 filed Apr. 13, 2012, and entitled “Cold Heavy Oil Production System and Methods,” which is hereby incorporated herein by reference in its entirety.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND

The disclosure relates generally to systems and methods for recovering subterranean hydrocarbons. More particularly, the disclosure relates to systems and methods for cold heavy oil production with sand in a horizontal or deviated wellbore.

Unconventional sources of oil, such as oil shales, oil sands and heavy oil contain unique physical properties that require particularized systems, techniques and procedures to allow for their effective and economic extraction and production. For instance, heavy oil has a relatively high density and viscosity, which present recovery challenges as it is more resistant to flow than lighter crude oils. Challenges associated with resistance to flow may be even greater in cold weather applications, such as production systems targeting recovery of heavy oil from reservoirs in Canada and Alaska. However, while unconventional oil supplies like heavy oil present unique challenges, rapidly dwindling supplies of traditional sources of oil have made the production of unconventional oil sources, such as heavy oil, more economically attractive.

In general, heavy oil may be extracted using primary, secondary, tertiary or mining methods. Primary extraction methods, also referred to as “cold production,” rely on natural forces within the formation, such as pressure generated by a proximal gas cap or gravity drainage, etc., to produce heavy oil from a subterranean formation. One particular form of primary extraction is cold heavy oil production with sand (CHOPS). CHOPS is similar to techniques used for extracting traditional sources of oil, with one significant deviation being that sand is produced from the reservoir along with the heavy oil. The production of sand from the well using the CHOPS method allows for the creation of “worm holes” in the formation proximal the wellbore. These worm holes act as conduits for the production of more sand and oil into the wellbore, which may be pumped to the surface for recovery. Secondary methods often involve the use of injecting materials into the well in order to enhance production, such as through injecting water, natural gas or carbon dioxide into the well. Tertiary methods, such as steam assisted gravity drainage (SAGD), often involve heating the heavy oil through injecting high temperature steam into the well in an effort to lower the viscosity of the oil and enhance the mobility of the oil such that it may more easily be produced from the formation.

Secondary and tertiary methods, while effective in some instances for recovering heavy oil, may have several disadvantages with respect to primary or cold production methods. For instance, secondary and tertiary methods often have an increased cost due to their reliance on injecting additional materials and energy into the well, such as water, natural gas and steam. Injecting additional material into the well may also be undesirable. While primary recovery methods, such as CHOPS, may not face these particular issues, they may have other drawbacks, such as lower recovery rates. For instance, CHOPS performed on a vertical wellbore may be limited in production due to the vertical well having less than optimal exposure to the oil producing formation.

BRIEF SUMMARY OF THE DISCLOSURE

These and other needs in the art are addressed in one embodiment by a system for producing hydrocarbons and sand from a formation. In an embodiment, the system comprises a wellbore having a substantially horizontal portion traversing the formation. In addition, the system comprises a liner disposed in the substantially horizontal portion of the wellbore. The liner has a longitudinal axis and includes a plurality of slots. Each slot is configured to pass sand from the formation into the wellbore. Further, the system comprises a production string extending through the wellbore. Still further, the system comprises a pump disposed at a downhole end of the production string and disposed in the liner. The pump has a central axis, an outlet coupled to the downhole end of the production tubing, and an inlet distal the production string. The pump is configured to pump hydrocarbons and sand from the formation to the surface. The central axis of the pump is oriented at an angle α measured downward from vertical. The angle α is between 60° and 90°.

These and other needs in the art are addressed in another embodiment by a system for producing hydrocarbons and sand from a formation. In an embodiment, the system comprises a wellbore having a substantially horizontal portion traversing the formation. In addition, the system comprises a liner disposed in the substantially horizontal portion of the wellbore. The liner has a longitudinal axis and includes a plurality of slots. Further, the system comprises a production string disposed in the wellbore. Still further, the system comprises a pump having an outlet end coupled to a downhole end of the production string and an inlet end distal the production string. The pump is disposed in the liner and is configured to pump sand and hydrocarbons through the production string to the surface. Moreover, the system comprises a tailpipe coupled to the inlet end of the pump and disposed in the liner. The tailpipe is configured to flow sand and hydrocarbons to the pump.

These and other needs in the art are addressed in another embodiment by a method for producing hydrocarbons from a wellbore having a substantially horizontal portion traversing a formation comprising sand. In an embodiment, the method comprises (a) determining a maximum grain size of the sand in the formation. In addition, the method comprises (b) inserting a liner into the substantially horizontal portion of the wellbore. The liner has a longitudinal axis and a plurality of circumferentially spaced elongate slots. Each slot is oriented parallel to the longitudinal axis and has a width that is at least 95% of the maximum grain size of the sand. Further, the method comprises (c) coupling a tailpipe to an inlet end of a pump. Still further, the method comprises (d) coupling a production string to an outlet end of the pump. Moreover, the method comprises (e) positioning the pump and the conduit in the liner after (d).

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed description of the preferred embodiments of the disclosure, reference will now be made to the accompanying drawings in which:

FIG. 1 is a schematic, cross-sectional view of an embodiment of a cold heavy oil production system in accordance with the principles described herein;

FIG. 2 is a top view of a segment of the production liner of the system of FIG. 1;

FIG. 3 is a schematic, cross-sectional view of an embodiment of a cold heavy oil production system in accordance with the principles described herein; and

FIG. 4 is a schematic, cross-sectional view of the downhole section of the system of FIG. 3.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

The following discussion is directed to various exemplary embodiments. However, one skilled in the art will understand that the examples disclosed herein have broad application, and that the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to suggest that the scope of the disclosure, including the claims, is limited to that embodiment.

Certain terms are used throughout the following description and claims to refer to particular features or components. As one skilled in the art will appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name but not function. The drawing figures are not necessarily to scale. Certain features and components herein may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in interest of clarity and conciseness.

In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . .” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection of the two devices, or through an indirect connection via other intermediate devices, components, and connections. In addition, as used herein, the terms “axial” and “axially” generally mean along or parallel to a central axis (e.g., central axis of a body or a port), while the terms “radial” and “radially” generally mean perpendicular to the given axis. For instance, an axial distance refers to a distance measured along or parallel to the axis, and a radial distance means a distance measured perpendicular to the axis. The term “heavy crude oil” or “heavy oil” is intended to mean any type of oil or oil source that does not flow easily.

Systems and methods for producing hydrocarbons are disclosed herein. Embodiments described herein can be employed in various hydrocarbon production applications, but are particularly suited for producing cold heavy oil with sand from a horizontal or deviated wellbore.

Referring now to FIG. 1, an embodiment of a cold heavy oil production system 10 is shown. In this embodiment, system 10 generally comprises a wellbore 11 extending from a wellhead 12 disposed at the surface 2 and penetrating a subterranean formation 3, a “Christmas tree” or production manifold 13 coupled to wellhead 12, and a production string 14 extending from the surface 2 through at least a portion of wellbore 11.

Subterranean formation 3 comprises heavy oil and a layer of permafrost 4 extending from the surface 2 to a certain depth within the formation 3. Permafrost 4 comprises soil or other formation material at or below the freezing point of water (32° F./0° C.). Permafrost 4 may contain ice, depending on the composition of the formation 3. In some applications, the layer of permafrost 4 in the formation 3 may extend at least several hundred feet vertically from the surface 2.

In this embodiment, wellbore 11 includes a substantially vertical section 11a extending from the surface 2 to an elbow or kickoff point 11b disposed vertically below permafrost 4. Wellbore 11 also includes a horizontal or deviated section 11c having an approximate dogleg severity of less than 5° per 100 feet and extending from kickoff point 11b to a terminus or toe 11d. Casing 15 extends from wellhead 12 through vertical section 11a of wellbore 11, and a liner 16 extends through deviated section 11c of wellbore 11. An annulus 17 extends through wellbore 11 and is disposed about string 14. As will be described in more detail below, liner 16 includes a plurality of circumferentially and axially spaced slots or perforations that allow fluid communication between wellbore 11 and formation 3.

Manifold 13 is coupled to wellhead 12 and seals wellbore 11 from the surrounding environment at the surface 2. Manifold 13 includes a plurality of valves, spools and other equipment for controlling and regulating the flow of fluids from wellbore 11 through production string 14.

Production string 14 is an elongate tubular with has an uphole end 14a coupled to manifold 13 at wellhead 12 and a downhole end 14b in deviated section 11c. String 14 functions as a conduit for transporting materials produced from formation 3 through wellbore 11 to manifold 13. In general, production string 14 can comprise any tubular for producing fluids to the surface, however, in this embodiment, production string 14 is coiled tubing. A pump 18 is disposed at downhole end 14b of string 14. In particular, pump 18 has a first or uphole end 18a coupled to end 14b of string 14 and a second or downhole end 18b distal end 14b. Downhole end 18b of pump 18 includes an opening to provide fluid communication between wellbore 11 and production string 14. Pump 18 transports sand and hydrocarbons through string 14 to manifold 13. In this embodiment, pump 18 is a progressive cavity pump having a downhole stator and a rotor driven by a rod. Pump 18 is oriented at an inclination angle α measured downward from vertical. In embodiments described herein, inclination angle α is preferably between 60° and 90°, more preferably between 70° and 80°, and even more preferably about 75° .

Referring now to FIG. 2, a segment of liner 16 is shown. In this embodiment, liner 16 has a longitudinal axis 26 and a plurality of circumferentially and axially spaced elongate slots 28 extending radially therethrough (i.e., slots 28 extend radially from the outer surface of liner 16 to the inner surface of liner 16). Slots 28 define passages through liner 16 and establish fluid communication between formation 3 and annulus 17.

In this embodiment, each slot 28 is rectangular—each slot 28 extends along a linear longitudinal axis between a first end 29 and a second end 30. In addition, in this embodiment, each slot 28 is oriented parallel to axis 26 of liner 16. In other words, the longitudinal axis of each slot 28 is oriented parallel to axis 26. Each slot 28 has a length L₂₈ measured between ends 29, 30 and a width W₂₈ measured circumferentially between the lateral sides of slot 28. Length L₂₈ is preferably between 2.0 in. and 4.0 in. Further, the number and size of slots 28 is preferably selected such that slots 28 define 3% of the outside surface area of liner 16.

The width W₂₈ of slots 28 is preferably sized to allow the flow of sand therethrough from formation 3 into annulus 17. In general, formation 3 includes a population of sand grains having sizes/diameters that vary across a statistical distribution. The sand grain diameters can be characterized based on their positions along the distribution ranging from the smallest to the largest grain sizes in formation 3, where for example, diameter D₅₀ represent the median sand grain diameter of the distribution (i.e., sand grains having a diameter right in the middle of the distribution of sand grain sizes in formation 3), diameter D₄₀ represents the sand grain diameter at the 40^th percentile of the distribution (i.e., sand grains having a diameter greater than 40% of the sand grains in formation 3), diameter D₉₀ represents the sand grain diameter at the 90^th percentile of the distribution (i.e., sand grains having a diameter greater than 90% of the sand grains in formation 3), etc. The degree of uniformity or “sorting” of the diameters of the sand grains that makeup formation 3 can be determined via calculating a uniformity coefficient of formation 3, sometimes defined as the ratio of the sand grain diameter at the 40th percentile of all sand grains of formation 3 over the sand grain diameter at the 90th percentile of all sand grains (i.e., D₄₀/D₉₀). The sand grain sizing, statistical distribution, and uniformity parameters can be determined by obtaining and analyzing one or more core samples of sand grains from formation 3. For instance, a core sample of the formation 3 may be procured and a particle analysis can be performed on the core sample.

In the exemplary embodiment of FIG. 2, the width W₂₈ of slots 28 is preferably selected such that each slot 28 is wider than the width of 95% of the sand particles in the formation 3 (i.e., the width W₂₈ is preferably greater than diameter D₉₅ of the sand grains at the 95^th percentile of the distribution). In other embodiments, slots 28 may be sized such that they are greater than the width of 75% of the sand particles in the formation 3 (i.e., diameter D₇₅). For most formations, the width W₂₈ of slots 28 preferably ranges between 0.010″-0.150″, and in this embodiment, width W₂₈ of slots 28 is 0.125″. In other embodiments, slots 28 may have a different cross-sectional shape, such as circular, triangular, etc., that are configured to allow the passage of sand particles through the slot having a size greater than 95% of the sand in the formation 3.

Liner 16 has an internal diameter (ID) configured to allow for the passage of sand within wellbore 11 from formation 3 without forming a blockage therein. For most applications, liner 16 preferably has an ID between 5.0″ and 7.0″, however, in this embodiment, liner 16 has an ID of 6.125″ and an outer diameter (OD) of 7″. The ID of liner 16 may be sized so as to allow flow of sand containing fluid in a horizontal flowpath. A larger diameter ID of liner 16 allows for sand to accumulate on the bottom of the liner 16 without resulting in a blockage of wellbore 11 as material is allowed to flow over the accumulated sand.

Referring now to FIGS. 3 and 4, another embodiment heavy oil production system 10′ is shown. System 10′ is substantially the same as system 10 previously described except that system 10′ includes a tailpipe 20 extending from pump 18 through deviated portion 11c of wellbore 11. Tailpipe 20 has a first or uphole end 20a coupled to pump 18 and a second or downhole end 20b distal pump 18. Downhole end 20b is open, thereby defining an intake 21. In this embodiment, intake 21 of tailpipe 20 is disposed at the vertically deepest section of wellbore 11 and is oriented at an angle β measured upward from vertical. In other words, the central axis of tailpipe 20 at intake 21 is oriented at angle β measured upward from vertical. To help ensure intake 21 of tailpipe 20 is positioned proximal the first sump of wellbore 11 (i.e., low spot along the substantially horizontal section 11c where sand is most likely to collect), tailpipe 20 is advanced through substantially horizontal section 11c until angle β is preferably 85° to 90°, more preferably 89° to 90°, and even more preferably as close to 90° as possible. In addition, tailpipe 20 includes a slotted joint 20c (FIG. 4) that is about 30 feet in length and positioned proximal uphole end 20a. In this embodiment, the slots in slotted joint 20c are oriented and shaped the same as slots 28 previously described, but preferably have a circumferential width greater than width W₂₈ of slots 28. Slotted joint 20c in tailpipe 20 allows for increased fluid flow area into string 14 to allow for continued fluid flow into tailpipe 20 in the event that intake 18 of tailpipe 20 becomes plugged due to the production of large sand-influxes. In order to mitigate the chance of the creation of flow blockages into tailpipe 20, tailpipe 20 and/or liner 16 are preferably sized such that approximately 0.75 in. of clearance is provided between the outer surface of tailpipe 20 and the inner surface of liner 16.

Pump 18 pumps sand and hydrocarbon containing materials through tailpipe 20 and production string 14 to wellhead 12 and manifold 13. Since sand flowing through string 14 may be abrasive, the inner surface of string 14 is preferably treated or lined with an erosion resistive material, such as high density polyethylene (HDPE) or the like.

Referring still to FIGS. 3 and 4, in this embodiment, production string 14 includes a heat trace 30 and a chemical injection line 31. Heat trace 30 transfer thermal energy (i.e., heat) to production string 14, which in turn transfers thermal energy to fluids flowing through string 14. In this embodiment, heat trace 30 is coupled to the outer surface of production string 14 and extends longitudinally thereon from an upper end 30a at the surface 2 to a terminal lower end 30b proximal the bottom of the permafrost 4. Thus, heat trace 30 extends substantially through permafrost 4, thereby at least partially offsetting any heat transfer from fluid within production string 14 to permafrost 4. In general, heat trace 30 can comprise any thermal energy producing electrical conductor known in the art.

Chemical injection line 31 supplies and injects chemicals into a downhole segment of string 14. In this embodiment, line 31 is coupled to the outer surface of string 14 and extends longitudinally along string 14 from an upper end 31 a at the surface 2 to a lower chemical injection point 31b positioned proximal pump 18 (e.g, immediately uphole of pump 18). Injection point 31b is positioned to inject a chemical into production string 14, such as a diluent(s) or other chemicals known in the art to reduce the viscosity of hydrocarbons (e.g., viscous or heavy oil) flowing through string 14. By reducing the viscosity of fluid within production string 14, it can be more easily and effectively transported to the surface 2. It should be appreciated that other chemicals can be injected at injection point 31b to affect other physical or chemical properties of materials disposed within production string 14. Although injection point 31b is positioned along string 14 adjacent pump 18 in this embodiment, in other embodiments, the injection point (e.g., injection point 31b) can be positioned at other locations such as along the tailpipe (e.g., tailpipe 20).

Referring still to FIG. 4, in this embodiment, production string 14 also includes a sump pressure sensor 25a disposed proximal to the intake 21 of tailpipe 20, a discharge pressure sensor 25b disposed proximal to the discharge end of pump 18, and an annulus pressure sensor 25c is disposed proximal to discharge pressure sensor 25b and pump 18. Sump pressure sensor 25a is coupled to tailpipe 20, and continuously measures and communicates (to the surface 2) the fluid pressure at intake 21. Discharge pressure sensor 25b is coupled to production string 14, and continuously measures and communicates (to the surface 2) the pressure of fluid exiting pump 18. Annulus pressure sensor 25c is coupled to production string 14, and continuously measures and communicates (to the surface 2) the pressure of fluid within wellbore 11 just uphole of pump 18. Pressure measurements from discharge pressure sensor 25b inform an operator of system 10 whether pump 18 is over-pressured with respect to its maximum operating discharge pressure. Annulus pressure sensor 25c and sump pressure sensor 25a are used by an operator of system 10 to determine if gas is entering wellbore 11 from the formation 3 or if a blockage of sand has been formed within wellbore 11 between pressure sensor 25c and pressure sensor 25a. For instance, pressure measurements from sensors 25c, 25a can be compared to the hydrostatic pressure that is expected to exist at those particular vertical depths in wellbore 11 given the average composition of material within wellbore 11 (e.g., sand, water and oil). If pressure measurements from sensors 25c, 25a drop below that hydrostatic pressure, then gas may be being produced into wellbore 11. If the pressure measurement of sensor 25c is higher than the hydrostatic pressure, then sand may be building up within wellbore 11 above sensor 25c, due to the relatively higher density of sand versus liquid hydrocarbon containing materials. Also, the differential pressure across pump 18 (i.e., difference in pressure readings between sensor 25b and sensor 25a) can be monitored in conjunction with the amount of torque being applied to the rotor of pump 18. For instance, a higher differential pressure across pump 18 and an increase in torque applied against the rotor of pump 18 by materials being displaced through the pump may be indicative of a sand blockage.

Pump 18 is positioned deep in the deviated section 11c of wellbore 11 at angle α as previously described. Tailpipe 20 extends from the intake of pump 18 to intake 21. Intake 21 is disposed at the vertically deepest section of wellbore 11 at toe 11d and at an angle β as previously described.

Liner 16 is disposed in the deviated portion 11c of wellbore 11. Next, pump 18 and tailpipe 20 are positioned below the most uphole slots 28 within liner 16, such that sand displaced into wellbore 11 from the most uphole slots 28 within liner 16 can flow downhole through wellbore 11 before entering slotted joint 20c and/or intake 21 at second end 20b. In this embodiment, pump 18 is positioned proximal the most uphole slots 28 of liner 16. In addition, in this embodiment, the axial or longitudinal distance of tailpipe 20 is approximately 300 feet, and thus, sand or other materials entering the most uphole slots 28 of liner 16 must travel at least 300 feet before entering intake 21. In other embodiments, pump 18 can be positioned longitudinally uphole of the most uphole slots 28 of liner 16.

Referring still to FIG. 4, a counter-weighted sub 35 is positioned along tailpipe 20 adjacent to and immediately downhole from pump 18. Sub 35 includes at least one exhaust port 35a coupled to a capillary tube 36 extending from port 35a to the expected operating fluid level in the annulus formed in wellbore 11 about string 14, where the expected operating level corresponds to the distance from the surface that fluid within wellbore 11 would be expected to rise to during production. Ports 35a and tube 36 allow gases flowing through tailpipe 20 to escape prior to entering pump 18. Sub 35 is counter-weighted such that it is configured to position exhaust ports 35a on the high side of tail pipe 20 (i.e., closer to the surface 2), which allows for more efficient separation of the entrained gas. In this embodiment, the total flow area provided by ports 35a is configured to allow entrained gas to escape with less than 5.0 pounds per square inch (PSI) pressure drop. A tag-sub 38 is also positioned along tailpipe 20 adjacent to and downhole from sub 35 and is configured to allow for the proper space-out for the rotor of pump 18 and to allow for coiled tubing access from the surface 2 to the tailpipe 20 and toe 11d of wellbore 11. In this embodiment, tag-sub 38 has a cylindrical tubular body with an inner diameter that is smaller than the major diameter of the rotor, thereby preventing the rotor from passing therethrough, but sufficiently large to allow coiled tubing to pass therethrough.

While system 10′ is shown and described as including tailpipe 20, heat trace 30, chemical injection line 31, and counterweight sub 35, in general, embodiments of cold heavy production systems in accordance with the principles described herein need not include all of these features and may only include one or more in different combinations. Further, it may be advantageous to provide one or more of these features in cold heavy production systems featuring a wellbore geometry that deviates from the geometry of wellbore 11, which may arise in applications due to reservoir target step-out distance.

A method for producing cold heavy oil with sand from a horizontal or deviated wellbore is provided herein. Referring to FIGS. 1 and 3, wellbore 11 is designed and drilled to include a substantially vertical portion 11a and a horizontal or deviated portion 11c as previously described. Once wellbore 11 has been extended from the surface 2 to kickoff point 11b below permafrost 4, the deviated portion 11c is drilled with less than a 5° per 100 feet dogleg severity. In other embodiments, horizontal or deviated portion 11c is drilled with less than a 1-4° per 100 feet dogleg.

The substantially horizontal portion 11c of wellbore 11 allows for the transport of sand through wellbore 11 without a significant risk of blockage. The deepest part of the deviated section 11c of wellbore 11 is drilled to no less than an 85° measured downward from vertical at the toe 11d. Liner 16 is installed in the deviated portion 11c of the wellbore 11, with slots 28 configured to allow the passage of sand from the formation 3 to the wellbore 11, where the sand may be produced at least 20% below the bubble point pressure of the formation fluid. Further, the ID of liner 16 is selected to maintain adequate velocity of material within wellbore 11 so that sand settles to less than ⅔ of ID of liner 16 over the time it takes to travel longitudinally along the liner 16. Transport correlations based on factors such as sand grain sizing of formation 3 and carrier fluid viscosity may be used in order to determine the proper sizing of the ID of liner 16 to achieve the desired fluid velocity within wellbore 11.

Production string 14 is advanced through wellbore 11 and pump 18 is positioned in the portion of deviated section 11c oriented at a 70° to 80° inclination measured downward from vertical to enable the positioning of pump 18 at angle α previously described. In addition, intake 21 of tailpipe 20 is positioned within the deepest portion of wellbore 11 and proximal to or longitudinally downhole the most uphole set of slots 28 of liner 16.

In one exemplary embodiment, production through systems 10, 10′ is initiated through recirculating oil through wellbore 11 and production string 14 to remove excess water, brine and other materials from wellbore 11. Recirculation of fluid through wellbore 11 may continue until pressure measurements from sensors 25a, 25b, 25c indicate that oil is present within production string 14. Next, a “beanup” procedure is commenced to align grains of sand proximal to slots 28 in liner 16 so as to form wormholes within formation 3. As part of the beanup procedure, the discharge pressure of pump 18, as measured by sensor 25b, is slowly increased to avoid collapsing wormholes in formation 3 or “slugging” sand into wellbore 11. In an embodiment, the difference between the static pressure of fluids in section 11c proximal pump 18 and tailpipe 20 (e.g., without any pumping) and the pressure at the intake of pump 18 during pumping operations, also known as the drawdown from pump 18, is increased by no more than 2.0 pounds per square inch (psi) per hour until significant sand influx into wellbore 11 from formation 3 is noted from either sensors 25a, 25b, 25c or detected at the surface 2. The increase in drawdown can be accomplished by rotating a rotor of pump 18 at a relatively higher speed in revolutions per minute (RPM). Once sand-cuts (i.e., the portion of the materials displaced within production string 14 that is sand) from production string 14 exceed approximately 0.5%-1.0%, the drawdown rate of pump 18 is held constant while maintaining adequate fluid velocity within string 14 to help ensure adequate sand transport until sand-cuts from materials produced from production string 14 stabilize. Once sand-cuts have stabilized, drawdown may be increased, increasing the amount of material produced from production string 14. The process of maintaining the drawdown rate relatively constant until sand-cut production has stabilized is repeated until either (a) a maximum sand-cut of 15-25%, and more preferably 20%, is produced from string 14, or (b) equipment limits of sand-cut production have been reached.

In another embodiment, a slotted liner is provided including a plurality of slots (similar in geometry as slots 28 of liner 16) having a width that is approximately 1.3 times larger than the width of sand grains having a width that is greater than 95% of the sand grains disposed in the reservoir. In that embodiment, the flow rate of fluid into production string 14 is approximately 900 barrels per day per 1,000 feet of exposure in the reservoir at an approximate mobility of approximately 1 millidarcy/centipoise (mD/cP). Further, if the desired rate of hydrocarbon production of the well system is not satisfied at a bottomhole pressure of approximately 20% below the bubble point pressure of the reservoir, sand production from the formation may be induced by using rapid drawdown changes. For instance, drawdown changes greater than 40 psi per hour with hold periods may be used after a measurable sand-cut, such as 1%, is detected.

During production, a chemical, such as a diluent or other viscosity reducing agent, is preferably injected into string 14 at injection point 31b to enhance the flow of hydrocarbons therethrough. In addition, in cases where wellbore 11 extends through permafrost 4, string 14 is preferably heated with heat trace 30.

In the manner described, embodiments described herein reduce and/or eliminate the economic and environmental disadvantages of injecting material and energy into the well in order to boost production. Further, embodiments described herein a particularly suited for horizontal or deviated wellbores, which offer the potential for enhanced exposure to the hydrocarbon containing formation.

While preferred embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the scope or teachings herein. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the systems, apparatus, and processes described herein are possible and are within the scope of the disclosure. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims. Unless expressly stated otherwise, the steps in a method claim may be performed in any order. The recitation of identifiers such as (a), (b), (c) or (1), (2), (3) before steps in a method claim are not intended to and do not specify a particular order to the steps, but rather are used to simply subsequent reference to such steps.

Claims

1. A system for producing hydrocarbons and sand from a formation, the system comprising:

a wellbore having a substantially horizontal portion traversing the formation;

a liner disposed in the substantially horizontal portion of the wellbore, the liner having a longitudinal axis and including a plurality of slots, wherein each slot is configured to pass sand from the formation into the wellbore;

a production string extending through the wellbore; and

a pump disposed at a downhole end of the production string and disposed in the liner, wherein the pump has a central axis, an outlet coupled to the downhole end of the production tubing, and an inlet distal the production string, wherein the pump is configured to pump hydrocarbons and sand from the formation to the surface;

wherein the central axis of the pump is oriented at an angle α measured downward from vertical, wherein the angle α is between 60° and 90°.

2. The system of claim A1, wherein the angle α is 75°.

3. The system of claim 1, wherein each slot in the liner has a circumferential width greater than a median size sand particle in the formation.

4. The system of claim 3, wherein the circumferential width of each slot in the liner is greater than 95% of the sand particles in the formation.

5. The system of claim 1, wherein each slot in the liner has a length between 2.0 and 4.0 in.

6. The system of claim 1, wherein the plurality of slots in the liner comprises a first set of circumferentially spaced slots and a second set of circumferentially spaced slots axially spaced from the first set of slots;

wherein the pump is axially positioned between the first set of slots and the second set of slots.

7. The system of claim 1, further comprising a heat trace coupled to the production string, wherein the heat trace is configured transfer thermal energy to the production string.

8. The system of claim 1, further comprising a chemical injection line coupled to the production string, wherein the chemical injection line has a downhole injection end positioned adjacent the outlet of the pump.

9. A system for producing hydrocarbons and sand from a formation, the system comprising:

a wellbore having a substantially horizontal portion traversing the formation;

a liner disposed in the substantially horizontal portion of the wellbore, wherein the liner has a longitudinal axis and includes a plurality of slots;

a production string disposed in the wellbore;

a pump having an outlet end coupled to a downhole end of the production string and an inlet end distal the production string, wherein the pump is disposed in the liner and is configured to pump sand and hydrocarbons through the production string to the surface; and

a tailpipe coupled to the inlet end of the pump and disposed in the liner, wherein the tailpipe is configured to flow sand and hydrocarbons to the pump.

10. The system of claim 9, wherein each slot in the liner has a width greater than 95% of the particles of sand in the formation.

11. The system of claim 9, wherein each slot in the liner has a length between 2.0 and 4.0 in.

12. The system of claim 9, wherein the plurality of slots in the liner comprises a first set of circumferentially spaced slots and a second set of circumferentially spaced slots axially spaced from the first set of slots;

wherein the pump is axially positioned between the first set of slots and the second set of slots.

13. The system of claim 9, wherein the liner has an outer diameter greater than or equal to 6.0 in.

14. The system of claim 9, further comprising a heat trace coupled to the production string, wherein the heat trace is configured transfer thermal energy to hydrocarbons flowing through the production string.

15. The system of claim 9, further comprising a chemical injection line coupled to the production string, wherein the chemical injection line is configured to inject chemicals into the hydrocarbons flowing through the production string.

16. The system of claim 15, wherein the chemical injection line has a downhole injection end positioned adjacent the outlet end of the pump.

17. The system of claim 9, wherein the tailpipe has a central axis, an uphole end coupled to the inlet end of the pump and a downhole end distal the pump, wherein the downhole end of the tailpipe comprises an intake, wherein the central axis of the tailpipe at the intake is oriented an angle β between 85° and 90° measured upward from vertical.

18. The system of claim 17, wherein the pump has a central axis oriented at an angle α between 60° and 90° measured downward from vertical.

19. The system of claim 18, wherein the angle β is between 89° and 90°; and

wherein the angle αis about 75°.

20. The system of claim 9, wherein the tailpipe comprises a slotted joint proximal the inlet end of the pump.

21. The system of claim 9, wherein the tailpipe includes a gas exhaust port proximal the pump, wherein the gas exhaust port is configured to flow gas separated from a fluid flowing through the tailpipe.

22. A method for producing hydrocarbons from a wellbore having a substantially horizontal portion traversing a formation comprising sand, the method comprising:

(a) determining a maximum grain size of the sand in the formation;

(b) inserting a liner into the substantially horizontal portion of the wellbore, wherein the liner has a longitudinal axis and a plurality of circumferentially spaced elongate slots, wherein each slot is oriented parallel to the longitudinal axis and has a width that is at least 95% of the maximum grain size of the sand;

(c) coupling a tailpipe to an inlet end of a pump;

(d) coupling a production string to an outlet end of the pump; and

(e) positioning the pump and the conduit in the liner after (d).

23. The method of claim 22, wherein (e) comprises:

(e1) orienting a central axis of the pump at an angle α between 60° and 90° measured downward from vertical;

(e2) orienting an intake of the tailpipe distal the pump at an angle β between 85° and 90° measured upward from vertical.

24. The method of claim 23, further comprising:

(f) operating the pump to simultaneously produce hydrocarbons and at least some of the sand in the formation to the surface.

25. The method of claim 24, wherein (f) comprises:

(f1) increasing drawdown of the wellbore by no more than 1-4 pounds per square inch per hour until sand is produced from the wellbore; and

(f2) maintaining a near constant drawdown of the wellbore until sand produced from the wellbore stabilizes.

26. The method of claim 25, further comprising repeating the method of claim 25 until a sand-cut of 1% to 25% is produced from the wellbore.