Hybrid Sand Control Systems and Methods for Completing a Wellbore with Sand Control

Abstract

A hybrid sand control system is provided herein. The sand control system is designed to reside and operate within a wellbore, preferably a wellbore that has been completed horizontally. The system utilizes compliant and non-compliant sand control assemblies placed in the wellbore across one or more zones of interest. The system has particular utility in connection with the control of sand migration across these zones within a surrounding open-hole portion of a wellbore. A method for completing a wellbore in a subsurface formation using the hybrid sand control system is also provided herein.

Description

BACKGROUND OF THE INVENTION

This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.

Field of the Invention

The present disclosure relates to the field of well completions. More specifically, the present invention relates to the isolation of formations in connection with wells that have been completed through multiple zones. This application also relates to the use of hybrid sand control assemblies in which alternating sand control devices that do and do not have a shape memory polymer material as a filtering medium are used to form a unique sand control system along a wellbore.

Discussion of Technology

In the drilling of oil and gas wells, a wellbore is formed using a drill bit that is urged downwardly at a lower end of a drill string. After drilling to a predetermined depth, the drill string and bit are removed and the wellbore is lined with a string of casing. An annular area is thus formed between the string of casing and the formation. A cementing operation is typically conducted in order to fill or “squeeze” the annular area with cement. The combination of cement and casing strengthens the wellbore and facilitates the isolation of formations behind the casing.

It is common to place several strings of casing having progressively smaller outer diameters into the wellbore. The process of drilling and then cementing progressively smaller strings of casing is repeated several times until the well has reached total depth. The final string of casing, referred to as a production casing, is cemented in place and perforated. In some instances, the final string of casing is a liner, that is, a string of casing that is not tied back to the surface.

As part of the completion process, a wellhead is installed at the surface. The wellhead controls the flow of production fluids to the surface, or the injection of fluids into the wellbore. Fluid gathering and processing equipment such as pipes, valves and separators are also provided. Production operations may then commence.

It is sometimes desirable to leave the bottom portion of a wellbore open. In open-hole completions, a production casing is not extended through the producing zones and perforated; rather, the producing zones are left uncased, or “open.” A “slotted” base pipe is then positioned inside the open wellbore extending down below the last string of casing. The slotted base pipe has openings sized for receiving production fluids while filtering solid formation particles above a designated size.

There are certain advantages to open-hole completions versus cased-hole completions. First, because open-hole completions typically have no perforation tunnels, formation fluids can converge on the wellbore radially 360 degrees. This has the benefit of eliminating the additional pressure drop associated with converging radial flow and then linear flow through particle-filled perforation tunnels. The reduced pressure drop associated with an open-hole completion virtually guarantees that it will be more productive than an unstimulated, cased hole in the same formation.

Second, open-hole techniques are oftentimes less expensive than cased hole completions. For example, the use of slotted base pipes eliminates the need for cementing, perforating, and post-perforation clean-up operations. Further, the use of a slotted base pipe, with or without a surrounding wire screen along the base pipe, helps maintain the integrity of the wellbore while allowing substantially 360 degree radial formation exposure.

FIG. 1A is a cross-sectional view of an illustrative wellbore 100A. The wellbore 100A defines a bore 105 that extends from a surface 101, and into the earth's subsurface 110. The wellbore 100A is completed to have an open-hole portion 120A at a lower end of the wellbore 100. The wellbore 100A has been formed for the purpose of producing hydrocarbons for processing or commercial sale. A string of production tubing 130 is provided in the bore 105 to transport production fluids from the open-hole portion 120A up to the surface 101.

The wellbore 100A includes a well tree, shown schematically at 124. The well tree 124 includes a shut-in valve 126. The shut-in valve 126 controls the flow of production fluids from the wellbore 100. In addition, a subsurface safety valve 132 is provided to block the flow of fluids from the production tubing 130 in the event of a rupture or catastrophic event above the subsurface safety valve 132. The wellbore 100A may optionally have a pump (not shown) within or just above the open-hole portion 120 to artificially lift production fluids from the open-hole portion 120A up to the well tree 124.

The wellbore 100A has been completed by setting a series of pipes into the subsurface 110. These pipes include a first string of casing 102, sometimes known as surface casing or a conductor. These pipes also include at least a second 104 and a third 106 string of casing. These casing strings 104, 106 are intermediate casing strings that provide support for walls of the wellbore 100A. Intermediate casing strings 104, 106 may be hung from the surface, or they may be hung from a next higher casing string using an expandable liner or liner hanger. It is understood that a pipe string that does not extend back to the surface (such as casing string 106) is normally referred to as a “liner.”

In the illustrative wellbore arrangement of FIG. 1A, intermediate casing string 104 is hung from the surface 101, while casing string 106 is hung from a lower end of casing string 104. Additional intermediate casing strings (not shown) may be employed. The present inventions are not limited to the type of casing arrangement used.

Each string of casing 102, 104, 106 is set in place through a cement column 108. The cement column 108 isolates the various formations of the subsurface 110 from the wellbore 100A and each other. The column of cement 108 extends from the surface 101 to a depth “L” at a lower end of the casing string 106. It is understood that some intermediate casing strings may not be fully cemented, depending on local regulations.

An annular region 204 (seen in FIG. 2) is formed between the production tubing 130 and the casing string 106. A production packer 206 seals the annular region 204 near the lower end “L” of the casing string 106.

In many wellbores, a final casing string known as production casing is cemented into place at a depth where subsurface production intervals reside. The production casing is perforated in order to expose the wellbore to reservoir fluids in the surrounding formation. However, the illustrative wellbore 100A is completed as an open-hole wellbore. Accordingly, the wellbore 100A does not include a final casing string along the open-hole portion 120A.

In the illustrative wellbore 100A, the open-hole portion 120A traverses three different subsurface intervals. These are indicated as upper interval 112, intermediate interval 114, and lower interval 116. Upper interval 112 and lower interval 116 may, for example, contain valuable oil deposits sought to be produced, while intermediate interval 114 may contain primarily water or other aqueous fluid within its pore volume. This may be due to the presence of native water zones, high permeability streaks or natural fractures in the aquifer, or fingering from injection wells. In this instance, there is a probability that water will invade the wellbore 100A.

Alternatively, upper 112 and intermediate 114 intervals may contain hydrocarbon fluids sought to be produced, processed and sold, while lower interval 116 may contain some oil along with ever-increasing amounts of water. This may be due to coning, which is a rise of near-well hydrocarbon-water contact. In this instance, there is again the possibility that water will invade the wellbore 100A.

Alternatively still, upper 112 and lower 116 intervals may be producing hydrocarbon fluids from a sand or other permeable rock matrix, while intermediate interval 114 may represent a non-permeable shale or otherwise be substantially impermeable to fluids.

In any of these events, it is desirable for the operator to isolate selected intervals. In the first instance, the operator will want to isolate the intermediate interval 114 from the production string 130 and from the upper 112 and lower 116 intervals (by use of packer assemblies 210′ and 210″) so that primarily hydrocarbon fluids may be produced through the wellbore 100 and to the surface 101. In the second instance, the operator will eventually want to isolate the lower interval 116 from the production string 130 and the upper 112 and intermediate 114 intervals so that primarily hydrocarbon fluids may be produced through the wellbore 100A and to the surface 101. In the third instance, the operator will want to isolate the upper interval 112 from the lower interval 116, but need not isolate the intermediate interval 114.

In the illustrative wellbore 100A of FIG. 1A, a series of sand screens 200 extends through the intervals 112, 114, 116. The sand screens 200 and connected packer assemblies 210′, 210″ are shown more fully in FIG. 2.

It is observed that the wellbore 100A of FIG. 1A is completed vertically. However, the majority of wells now being drilled in North America are being completed horizontally.

FIG. 1B is a perspective, cut-away view of a wellbore 100B that has been drilled horizontally. The wellbore 100B includes a vertical portion 160 that extends from the surface 101, and a horizontal section 170 that extends along a subsurface formation 150. The illustrative horizontal section represents an open-hole section 120B.

The horizontal portion 160 has a heel 162 and a toe 164. Along the horizontal section 160 the wellbore 100B has a series of zones 165. The zones are indicated as 165a, 165b, . . . 165i, 165j. Each zone 165 may have its own fluid flow and reservoir characteristics such as pressure, lithology and fluid composition. Thus, the sand screen and packer arrangement of FIG. 1A may be applied to the wellbore 100B of FIG. 1B to isolate selected zones.

Referring now to FIG. 2, FIG. 2 provides an enlarged cross-sectional view of the open-hole portion 120A of the wellbore 100A of FIG. 1A. The open-hole portion 120A and the three intervals 112, 114, 116 are more clearly seen. Each interval 112, 114, 116 may include a series of production zones, such as zones 165a, 165b, . . . 165j of FIG. 1B.

In FIG. 2, a series of sand control assemblies is also shown. Each sand control assembly 200 defines an elongated tubular body 205 extending along the intervals 112, 114, 116. Each tubular body 205 is made up of one or more base pipes threadedly connected end-to-end. The base pipes 205 have slots placed at strategic locations or along their lengths. In addition, the sand control assemblies 200 include a surrounding filter medium wound there around to form sand screens. The filter media may be wire mesh screens or helical wire wraps or ceramic wraps fitted around the base pipe 205. The filter media have parallel slots that prevent the inflow of sand or other particles above a pre-determined size into the base pipe 205 and the production tubing 130.

In addition to the sand control assemblies 200, the wellbore 100 includes one or more packer assemblies 210. In the illustrative arrangement of FIGS. 1A and 2, the wellbore 100A has an upper packer assembly 210′ and a lower packer assembly 210″. However, additional packer assemblies 210 or just one packer assembly 210 may be used. The packer assemblies 210′, 210″ are uniquely configured to seal an annular region 202 between the various sand screens 200 and a surrounding wall 201 of the open-hole portion 120A of the wellbore 100A.

The upper 210′ and lower 210″ packer assemblies are placed proximate upper and lower boundaries of the intermediate interval 114, respectively. Each packer assembly 210′, 210″ may have two separate packers. These packers 212, 214 may represent mechanically-set packers, wherein each packer is set through a combination of mechanical manipulation and hydraulic forces. Each packer 212, 214 has an expandable portion or element fabricated from an elastomeric or a thermoplastic material capable of providing at least a temporary fluid seal against a surrounding wellbore wall 201.

Details concerning setting and operation of mechanical packer assemblies in conjunction with gravel packing are disclosed in PCT Patent Appl. No. WO2012/082303 entitled “Packer for Alternate Flow Channel Gravel Packing and Method for Completing a Wellbore.” This publication describes a packer that may be mechanically set within an open-hole wellbore. This PCT application, published Jun. 21, 2102, is referred to and incorporated in its entirety herein by reference.

FIG. 2 shows a mandrel at 215 in the packers 212, 214. This may be representative of the piston mandrel, and other mandrels used in the packers 212, 214 as described more fully in the WO2012/082303 PCT application. The mandrels form part of a primary flow path for production fluids.

The upper 212 and lower 214 packers may generally be mirror images of each other, except for the release sleeves that shear respective shear pins or other engagement mechanisms. Unilateral movement of a setting tool (not shown) will allow the packers 212, 214 to be activated in sequence or simultaneously. The lower packer 214 is activated first, followed by the upper packer 212 as a mechanical shifting tool is pulled upward through an inner mandrel.

As a “back-up” to the expandable packer elements within the upper 212 and lower 214 packers, the packer assemblies 210′, 210″ may each also include an intermediate packer element 216. The intermediate packer element 216 defines a swelling elastomeric material fabricated from synthetic rubber compounds. Suitable examples of swellable materials may be found in Easy Well Solutions' Constrictor™ or SwellPacker™, and SwellFix's E-ZIP™. The swellable packer 216 may include a swellable polymer or swellable polymer material, which is known by those skilled in the art and which may be set by one of a conditioned drilling fluid, a completion fluid, a production fluid, an injection fluid, a stimulation fluid, or any combination thereof.

It is noted that a swellable packer 216 may be used alone or in lieu of the upper 212 and lower 214 packers. The present inventions are not limited by the presence or design of any packer assembly unless expressly so stated in the claims.

The packer assemblies 210′, 210″ help control and manage fluids produced from different zones. In this respect, the packer assemblies 210′, 210″ allow the operator to seal off an interval from either production or injection, depending on well function. Installation of the packer assemblies 210′, 210″ in the initial completion allows an operator to shut-off the production from one or more zones during the well lifetime to limit the production of water or, in some instances, an undesirable non-condensable fluid such as hydrogen sulfide.

The wellbore 100A may optionally have a gravel pack placed around the sand screens 200. In connection with the installation of gravel packs, fluid bypass technology has been developed to ensure a uniform installation of “gravel pack” along the length of sand screens. This bypass technology employs shunt tubes, or alternate flow channels, placed along selected lengths of sand screen joints. The tubes allow a gravel slurry to be transported downhole across premature sand bridges and even packers along a wellbore. Such fluid bypass technology is described, for example, in U.S. Pat. No. 5,588,487 entitled “Tool for Blocking Axial Flow in Gravel-Packed Well Annulus,” and PCT Publication No. WO2008/060479 entitled “Wellbore Method and Apparatus for Completion, Production, and Injection,” each of which is incorporated herein by reference in its entirety.

Additional references which discuss alternate flow channel technology include U.S. Pat. No. 7,971,642; U.S. Pat. No. 7,938,184; U.S. Pat. No. 7,661,476; U.S. Pat. No. 8,011,437; U.S. Pat. No. 8,186,429; U.S. Pat. No. 8,215,406; U.S. Pat. No. 8,430,160; and U.S. Pat. No. 8,789,612. See also M. T. Hecker, et al., “Extending Openhole Gravel-Packing Capability: Initial Field Installation of Internal Shunt Alternate Path Technology,” SPE Annual Technical Conference and Exhibition, SPE Paper No. 135,102 (September 2010); and M. D. Barry, et al., “Open-hole Gravel Packing with Zonal Isolation,” SPE Paper No. 110,460 (November 2007). The alternate flow channel technology enables a true zonal isolation in multi-zone, open hole gravel pack completions. The alternate flow channel technology is practiced under the name Alternate Path®, owned by ExxonMobil Corporation of Irving, Tex.

It has been observed that many well completions are not suited for gravel packing. These include, for example, wells that are completed in an extremely long horizontal dimension, such as greater than 5,000 feet. In this instance, the dragging (or, more accurately, pushing) of screens across long intervals of rock during run-in can damage the filter media and connections used for slurry bypass.

Sand screens fitted for gravel packing may also not be suited for wells that require multi-lateral completions. In this instance, long sand screen assemblies can become stuck. Some gravel packing systems are also not well suited for wells that are completed through zones of extremely high formation temperatures and pressures. In addition, it can be a challenge to transport gravel packing systems and operate gravel packing jobs in extremely remote locations. In any of these instances, the operator may just use basic sand screens without gravel packing, or even just slotted base pipes. In other instances, the operator may choke back the production rate without a sand control device to manage sand within an acceptable level.

A problem with wellbores completed without gravel packing, particularly those created across extended horizontal or vertical intervals, is that sand and fines that invade the formation tend to migrate. Those of ordinary skill in the art will understand that in some zones, the sand particles may be of sufficient diameter that they are blocked by the slots in the sand screen, in which case the sand screen has done its job. However, in other zones the sand particles (and fines associated with the formation), may partially enter the slots in the sand screen, causing the screen to become clogged. This can occur when the wellbore is completed through non-homogenous rock—a condition referred to as heterogeneity.

If sand particles and fines invade a wellbore, they will move towards the closest pressure sink along the wellbore and clog the sand screen joint at that area of low pressure. As the sand screen joint becomes clogged, sand particles and fines from that zone will start to move to a zone of next lowest pressure. Over time, multiple sand screen joints can become clogged, rendering the well in a substantially underperforming condition.

Recently, anew type of sand control device has been developed referred to as shape memory polymer, or “SMP.” Shape memory polymer devices comprise a downhole tubular body having a base pipe, and a surrounding layer of material that swells in response to a particular downhole condition. The downhole condition may be a certain temperature, a certain fluid, or a certain chemical that is injected by the operator into the wellbore. The SMP material will expand until it contacts the surrounding open hole formation. For this reason, SMP devices are considered “compliant.”

Various U.S. patents have issued, and various patent applications have been published, presenting shape memory polymer devices in various embodiments. These include U.S. Pat. No. 7,013,979; U.S. Pat. No. 7,318,481; U.S. Patent Publ. No. 2012/0067587; and U.S. Patent Publ. No. 2012/0211223. Two different SMP devices were recently disclosed in U.S. Patent Publ. No. 2011/0232901, wherein the SMP's overly each other or are axially adjacent to each other. The idea behind the inventions was to add flexibility of expansion over time and location. U.S. Patent Publ. 2015/0068760 disclosed an SMP device that used an additional filter to form inner and outer filtration layers for methane hydrate production. In this respect, an inner porous media was used, followed by a surrounding SMP layer.

The use of SMP devices have certain benefits. First, unlike the mechanically-set packers 212 and 214 and the swell packer 216 mentioned above, shape memory polymer devices remain permeable. Thus, the SMP material can expand into contact with the surrounding open hole wellbore and support the formation to prevent the invasion of particles and fines, while at the same time allowing formation fluids to flow through and into the base pipe. Second, SMP devices replace the use of swell packers as barriers to limit the migration of producing sand or fines along the annulus. Those of ordinary skill in the art will understand that the installation and expense of swell packers limit the use of large numbers downhole. In the case of an extended reach wellbore, a swell packer may only be placed every 150 to 300 feet, or much farther. Between the swell packers may still be zones where formation fluids and fines invade the wellbore, causing the screens to clog as described above. Thus, zonal isolation can actually back-fire, causing all producing zones between packers (such as packer assembly 210) to become non-producing zones.

Accordingly, a need exists for a hybrid sand control system that employs both compliant (such as SMP) and non-compliant sand screens along an open hole wellbore. In addition, a need exists for methods of completing an open hole wellbore, wherein alternating compliant and fixed sand control devices are used.

SUMMARY OF THE INVENTION

A hybrid sand control system is first provided herein. The sand control system is designed to reside and operate within a wellbore. Preferably, the wellbore has been completed horizontally, though other inclinations may be appropriate. More preferably, the wellbore is an extended length wellbore that traverses multiple zones across more than 5,000 feet of hole. The system has particular utility in connection with the control of sand migration across these zones within a surrounding open-hole portion of a wellbore.

The hybrid sand control system first includes a plurality of compliant sand control assemblies. Each compliant sand control assembly has one or more joints of slotted or perforated base pipe threadedly connected in series. In addition, each compliant sand control assembly may have a shape memory polymer material, or SMP material. The SMP material resides around the slotted (or perforated) base pipe along at least a portion of its length. The SMP material is designed to expand into contact radially with a wellbore wall downhole in response to a wellbore condition. The wellbore condition may be, for example, a certain temperature, a certain pressure, a certain wellbore fluid, a certain fluid injected into the wellbore, or combinations thereof.

Each compliant sand control assembly may optionally have an intermediate filtering layer. The filtering layer may be a wire mesh screen, a wire-wrap screen, a ceramic screen, a woven mesh screen, or other filtering material. The intermediate filtering layer resides along a substantial length of the base pipes and under at least the length of the SMP material.

The sand control system next includes a plurality of fixed sand control assemblies. Each fixed sand control assembly also has one or more joints of slotted (or perforated) base pipe threadedly connected in series. In addition, each fixed sand control assembly optionally has a surrounding filter screen along at least a portion of its length. Thus, the fixed sand control assemblies represent one or more joints of sand screen. The filter layer for the fixed sand control assembly will not compliantly engage the surrounding wellbore wall.

In one aspect, the joints of sand screen comprise several layers of material placed over the slotted base pipe. These may include, for example, a filter media support layer comprising longitudinal ribs, followed by a helically-wrapped wire screen, followed still by a woven wire cloth. A surrounding perforated protective shroud may then optionally be placed over the woven wire cloth. In another aspect, the joints of sand screen may comprise two or more filtering compartments arranged along the base in adjacent relation to form a circuitous (or maze) flow path. The circuitous path serves to equalize pressure along the length of a sand screen joint and minimize so-called hot spots during a production operation.

In the present invention, compliant sand control assemblies and fixed sand control assemblies are placed in the wellbore in alternating relation. In one aspect, each compliant sand control assembly is between 8 and 12 feet in length, while each fixed sand screen assembly is between 25 and 150 feet in length.

It is understood that each fixed sand screen assembly is made up one, and preferably three or four, individual joints of sand screen threadedly connected together. Each such joint is typically between 25 and 40 feet in length and receives filtered production fluids into joints of slotted (or perforated) base pipe. The base pipes are threadedly connected end-to-end.

A method for completing a wellbore in a subsurface formation is also provided herein. The wellbore preferably includes a lower portion completed horizontally. More preferably, the wellbore is an extended length wellbore that traverses multiple zones across more than 5,000 feet of horizontal (or at least deviated) hole.

The method first includes providing a plurality of compliant sand control assemblies. The compliant sand control assemblies are constructed in accordance with the compliant sand control assemblies described above in their various embodiments. In this respect, each compliant sand control assembly has one or more joints of slotted (including perforated) base pipe threadedly connected in series, and a shape memory polymer material, or SMP material, around the slotted base pipe along at least a portion of its length. The SMP material is permeable to fluids, but filters solids.

The method also includes providing a plurality of fixed sand control assemblies. The fixed sand control assemblies are also constructed in accordance with the various fixed sand screen joints described above in their various embodiments. In this respect, each fixed sand control assembly also has one or more joints of slotted (including perforated) base pipe threadedly connected in series, and, optionally, a surrounding filter screen along at least a portion of its length.

The method next includes running the compliant sand control assemblies and the fixed sand control assemblies into a wellbore. The sand control assemblies are run into the wellbore in such a manner that the compliant sand control assemblies and the fixed sand control assemblies are placed in the wellbore in alternating relation. In one aspect, each compliant sand control assembly is between 8 and 12 feet in length, while each fixed sand control assembly is between 25 and 150 feet in length.

The method may also include the step of identifying rock properties of certain zones along the wellbore. The method then includes locating the compliant sand control assemblies along pre-selected zones along the wellbore according to the identified rock properties. For example, certain zones may have an unconsolidated rock matrix, or may have excessively fine particles. In that instance, the operator may locate one of the compliant sand control assemblies at opposing edges of such zones.

The method also includes producing hydrocarbon fluids through the base pipes of the sand control assemblies along zones of interest. Producing hydrocarbon fluids causes hydrocarbon fluids to travel into the perforated base pipes, through the production tubing, and up to the surface.

The method additionally includes actuating the SMP material along the compliant sand control assemblies. As noted, the SMP material is designed to expand into contact radially with a wellbore wall downhole in response to an environmental condition. The environmental condition may be, for example, a certain temperature, a certain pressure, a certain wellbore fluid, a certain fluid injected into the wellbore, or combinations thereof.

The method may further optionally include the step of conducting a gravel packing operation between two or more selected compliant sand control assemblies. Such an operation would require the injection of sand slurry through shunt tubes along a fixed sand screen assembly in order to bypass the expanded SMP material.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the present inventions can be better understood, certain illustrations, charts and/or flow charts are appended hereto. It is to be noted, however, that the drawings illustrate only selected embodiments of the inventions and are therefore not to be considered limiting of scope, for the inventions may admit to other equally effective embodiments and applications.

FIG. 1A is a cross-sectional view of a first illustrative wellbore. The wellbore has been drilled vertically through three different subsurface intervals, each interval being under formation pressure and containing fluids.

FIG. 1B is a perspective, cut-away view of a second illustrative wellbore. Here, the wellbore has been drilled horizontally along a formation, and is being completed with sand control assemblies along multiple zones.

FIG. 2 is an enlarged cross-sectional view of an open-hole completion of the wellbore of FIG. 1A. The open-hole completion at the depth of the three illustrative intervals is more clearly seen.

FIG. 3A presents a side, cross-sectional view of an exemplary hybrid sand control system of the present invention, in one embodiment. FIG. 3A shows an enlarged view of the heel of the horizontally completed wellbore of FIG. 1B. Here, compliant and non-compliant sand control joints are connected in alternating arrangement across one illustrative zone of interest.

FIG. 3B presents a side, cross-sectional view of an exemplary hybrid sand control system of the present invention, in an alternate embodiment. FIG. 3B also shows an enlarged view of the heel of the horizontally completed wellbore of FIG. 1B. Here, compliant and non-compliant sand control joints are connected in alternating arrangement across one zone of interest. In this arrangement, transport conduits are used to conduct gravel packing between two of the actuated SMP devices.

FIG. 4A presents a side, cross-sectional view of a compliant sand control assembly as may be used in the sand control system of the present invention, in one embodiment. The compliant sand control assembly includes a base pipe and a surrounding shape memory polymer material.

FIG. 4B is another side, cross-sectional view of the compliant sand control assembly of FIG. 4A. Here, the SMP material has expanded into engagement with a surrounding wellbore wall.

FIG. 5A presents a side, cut-away view of a fixed sand control assembly as may be used in the sand control system of the present invention, in one embodiment. The fixed sand screen assembly includes, inter alia, a slotted base pipe, support ribs and a surrounding filter screen.

FIG. 5B is a cross-sectional view of the fixed sand screen assembly of FIG. 5A, taken across line B-B.

FIG. 6A presents another side, cut-away view of a fixed sand control assembly as may be used in the sand control system of the present invention. In this embodiment, the fixed sand screen assembly also includes a slotted base pipe, support ribs and a surrounding filter screen.

FIG. 6B is a cross-sectional view of the fixed sand control assembly of FIG. 6A, taken across line B-B.

FIG. 7 is a perspective view of a fixed control screen assembly as may be used in the sand control system of the present invention, in an alternate embodiment. The fixed sand screen assembly includes a base pipe and a surrounding filter screen. Here, the sand screen assembly offers more than one fluid flow compartments so as to equalize fluid pressure along the filter screen.

FIGS. 8A and 8B present a single flowchart for a method of completing a wellbore, in one embodiment. The method involves running a sand control system into a wellbore wherein compliant and fixed sand control assemblies are placed along one or more zones of interest within a wellbore in alternating relation.

DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS

Definitions

As used herein, the term “hydrocarbon” refers to an organic compound that includes primarily, if not exclusively, the elements hydrogen and carbon. Hydrocarbons generally fall into two classes: aliphatic, or straight chain hydrocarbons, and cyclic, or closed ring hydrocarbons, including cyclic terpenes. Examples of hydrocarbon-containing materials include any form of natural gas, oil, coal, and bitumen that can be used as a fuel or upgraded into a fuel.

As used herein, the term “hydrocarbon fluids” refers to a hydrocarbon or mixtures of hydrocarbons that are gases or liquids. For example, hydrocarbon fluids may include a hydrocarbon or mixtures of hydrocarbons that are gases or liquids at formation conditions, at processing conditions or at ambient conditions (15° C. to 20° C. and 1 atm pressure). Hydrocarbon fluids may include, for example, oil, natural gas, coal bed methane, shale oil, pyrolysis oil, pyrolysis gas, a pyrolysis product of coal, and other hydrocarbons that are in a gaseous or liquid state.

As used herein, the term “fluid” refers to gases, liquids, and combinations of gases and liquids, as well as to combinations of gases and solids, and combinations of liquids and solids.

As used herein, the term “production fluids” refers to those fluids, including hydrocarbon fluids, which may be received from a subsurface formation into a wellbore.

As used herein, the term “subsurface” refers to geologic strata occurring below the earth's surface.

The term “subsurface interval” refers to a formation or a portion of a formation wherein formation fluids may reside. The fluids may be, for example, hydrocarbon liquids, hydrocarbon gases, aqueous fluids, or combinations thereof. The terms “zone” or “zone of interest” may be used to refer to a portion of a subsurface interval.

As used herein, the term “wellbore” refers to a hole in the subsurface made by drilling or insertion of a conduit into the subsurface. A wellbore may have a substantially circular cross section, or other cross-sectional shape. As used herein, the term “well,” when referring to an opening in the formation, may be used interchangeably with the term “wellbore.”

DESCRIPTION OF SPECIFIC EMBODIMENTS

The inventions are described herein in connection with certain specific embodiments. However, to the extent that the following detailed description is specific to a particular embodiment or a particular use, such is intended to be illustrative only and is not to be construed as limiting the scope of the inventions.

Certain aspects of the inventions are also described in connection with various figures. In certain of the figures, the top of the drawing page is intended to be toward the surface, and the bottom of the drawing page toward the well bottom. While wells commonly are completed in substantially vertical orientation, it is understood that wells may also be inclined and or even horizontally completed. When the descriptive terms “up and down” or “upper” and “lower” or similar terms are used in reference to a drawing or in the claims, they are intended to indicate relative location on the drawing page or with respect to claim terms, and not necessarily orientation in the ground, as the present inventions have utility no matter how the wellbore is orientated.

The present disclosure presents novel sand control systems. The sand control systems are designed to reside and operate within a wellbore. Preferably, the wellbore has been completed horizontally. More preferably, the wellbore is an extended length wellbore that traverses multiple zones of interest across more than 5,000 feet of hole. The assembly has particular utility in connection with the control of sand migration across these zones within a surrounding open-hole portion of a wellbore.

The sand control system employs includes a plurality of compliant sand control assemblies and a plurality of fixed sand control assemblies. The system is designed to be run into a wellbore across selected zones of interest such that compliant and fixed sand control assemblies are in alternating relation.

FIG. 3A presents a side, cross-sectional view of an exemplary hybrid sand control system 320A of the present invention, in one embodiment. The system 320A resides within a wellbore 300A. The sand control system 320A may be placed in a wellbore that is completed substantially vertically, such as wellbore 100 of FIG. 1A. Alternatively, the sand control system 320A may be placed longitudinally along a formation 150 that is completed horizontally or that is otherwise deviated. As formation fluids enter the wellbore 300A under pressure, they flow into the sand control system 320A. The fluids then progress to the surface. The surface may be a land surface such as shown at surface 101 in FIG. 1A; alternatively, the surface may be an ocean or other water surface (not shown).

In FIG. 3A, the wellbore 300A is completed horizontally. A horizontal section 370. Is shown in enlarged view. The horizontal section includes a heel 162 and a toe (shown at 164 in FIG. 1B). The horizontal portion 370 of the wellbore 300A is being left uncased, leaving a wall 305 of the wellbore 300A without casing or cement.

It is observed that only a small length of the horizontal portion 370 is shown in FIG. 3A; however, it is understood from FIG. 1B that the horizontal portion 370 may extend over 5,000 feet, and even over 10,000 feet. The horizontal portion 370 may have numerous zones of interest 165a, 165b, . . . 165j spaced there along, extending to the toe 164.

Within the wellbore 300A above the horizontal portion 370 is a lower portion of a string of casing 308. A lower end of a string of production tubing 330 is seen extending down towards the horizontal portion 370. Of course, it is understood that the production tubing 330 will extend back up to the surface (seen at 101 in FIG. 1B). The production tubing 330 terminates at the heel 162. A packer 360 is provided near the bottom end of the production tubing 330. The packer 360 seals the annular area 335 between the production tubing 330 and a surrounding casing 308.

In the sand control system 320A of FIG. 3A, a series of compliant and non-compliant sand control joints are connected across an illustrative zone of interest 165a. In FIG. 3A, only one zone of interest 165a from FIG. 1B is shown; however, it is understood that the wellbore 300A will have many more zones, indicated at 165b, 165c, . . . 165j in FIG. 1B. In the illustrated zone 165a of FIG. 3A, three non-compliant sand control assemblies are shown at 365a. Each non-compliant sand control assembly 365a represents one or more tubular joints used for filtering sand or other formation particles. In addition, three compliant sand control devices 365b are shown along zone 165a. The three compliant sand control assemblies 365b represent sand control joints that have shape memory polymer material or may otherwise be expanded into engagement with a surrounding wellbore wall 305.

An annular region 363 is formed between the sand control assemblies 365a, 365b and the surrounding wellbore wall 305. Preferably, centralizers (not shown) are placed along the fixed sand control assemblies 365a within at least the horizontal portion 370.

Both the non-compliant sand control assemblies 365a and the compliant sand control assemblies 365b have slotted or perforated base pipes 325. The base pipes 325 permit an ingress of formation (or reservoir) fluids through openings (not shown), and then into a bore 350. The bore 350, in turn, is in fluid communication with a bore of the production tubing 330. In this way, valuable hydrocarbon fluids are transmitted to the surface 101.

The non-compliant sand control assemblies 365a are preferably slotted (including perforated) base pipes, with or without a surrounding wire wrap or other filter medium. When used, the surrounding wire wrap serves as a filter medium. The filter medium represents a wire wrapped sand screen, a ceramic sand screen, a woven mesh or other device that filters particles of a pre-determined size. As used herein, the term “sand screen” refers to any filtering mechanism configured to prevent passage of particulate matter having a certain size, while permitting the in-flow flow of gases, liquids and perhaps fine particles. The size of the filter will generally be in the range of 60-120 mesh, but may be larger or smaller depending on the specific environment. Many sand screen types are known in the art and include wire-wrap, mesh material, woven mesh, and sintered metal. The filtering medium may be metal or ceramic. Ceramic screens are available from ESK Ceramics GmbH & Co. of Germany. The screens are sold under the trade name PetroCeram®.

The non-compliant sand control assemblies 365a, or fixed sand screen joints, provide a matrix of fluid flow that permits an ingress of formation fluids while restricting the passage of sand particles over a certain gauge. Preferably, the sand screen joints offer materials and configurations that protect against areas of high velocity flow, referred to as “hot spots.” An example of such sand screens are those described in U.S. Patent Publ. No. 2014/0262260 entitled “Sand Control Screen Having Improved Reliability,” incorporated herein by reference. Certain embodiments in U.S. Patent Publ. No. 2014/0262260 create a tortuous flow path.

In the sand control system 300A of FIG. 3A, the compliant and non-compliant sand control assemblies 365a, 365b are alternated along the zone of interest 165a to form a hybrid sand control system. This allows the operator to obtain the unique and novel benefit of multiple sand screens 365a without the expense and complexity of packers or gravel packing, while also preventing the cross-migration of small particles and fines through the use of shape memory polymer devices 365b. Thus, if one fixed sand screen joint (or set of joints) 365a becomes clogged, the remaining sand screen joints 365a will not become clogged by the same migrating particles or fines. The compliant sand control devices 365b have the additional benefits of being economical enough that multiple of such devices 365b may be used, while also excluding formation sand and permitting formation fluids (such as hydrocarbon fluids) to flow through the polymer material and enter the bore 305 of the sand control system 320A.

It is observed from FIG. 3A that the compliant sand control assemblies 365b are slightly shorter than the fixed sand control assemblies 365a. Preferably, each compliant sand control assembly 365b is between 8 and 12 feet in length, while each fixed sand control assembly 365a is between 25 and 150 feet in length. It is understood that each fixed sand control assembly 365b is made up one, and preferably three or four, individual joints of sand screen threadedly connected together to form an extended length. The base pipes 325 are threadedly connected end-to-end.

Hybrid sand control provides multiple sand control devices with different characteristics to increase the opportunity of effective sand control or limit the ineffective sand control to selected intervals to maximize overall production. For example, under high downhole stress conditions, a compliant sand control device may be increasingly compressed against the surrounding wellbore. The stress will further increase with reservoir depletion and drawdown when production fluids are produced. In the event a compliant sand control device 365b is compressed or plugged to be much less permeable or even impermeable to reservoir fluids, the alternating fixed sand control devices 365a continue producing to mitigate the negative impact to overall production. Note that hybrid sand control is applicable to well injection, stimulation or other treatment as well.

FIG. 3B presents a side, cross-sectional view of an exemplary hybrid sand control system 320B of the present invention, in an alternate embodiment. The system 320B again resides within an open hole wellbore 300B.

In FIG. 3B, the wellbore 300B is again completed horizontally. A horizontal section 370 is shown in enlarged view. The horizontal section includes a heel 162 and a toe (shown at 164 in FIG. 1B). The horizontal portion 370 of the wellbore 300A is being left uncased, leaving a wall 305 of the wellbore 300A without casing or cement.

It is once again observed that only a small length of the horizontal portion 370 is shown in FIG. 3B; however, it is understood from FIG. 1B that the horizontal portion 370 may extend over 5,000 feet, and even over 10,000 feet. The horizontal portion 370 may have numerous zones of interest 165a, 165b, . . . 165j spaced there along.

In the sand control system 320B of FIG. 3B, a series of compliant and non-compliant sand control joints are again connected across the zone of interest 165. In FIG. 3B, only one zone of interest 165a from FIG. 1B is shown. However, it is again understood that the wellbore 300B will have many more zones, indicated at 165b, 165c, . . . 165j in FIG. 1B. In the illustrated zone 165a of FIG. 3B, three non-compliant sand control assemblies are shown at 365a′. Each non-compliant sand control assembly 365a′ represents one or more tubular joints used for filtering sand or other formation particles. In addition, three compliant sand control devices 365b are shown along zone 165a. The three compliant sand control devices 365b represent shape memory polymer devices.

Both the non-compliant (or “fixed”) sand screens 365a′ and the compliant sand control devices 365b have slotted or perforated base pipes 325. The base pipes 325 permit an ingress of formation fluids through slots, and then into a bore 350. The bore 350, in turn, is in fluid communication with the production tubing 330. In this way, valuable hydrocarbon fluids are transmitted to the surface 101.

The non-compliant sand control devices 365a′ are slotted (including perforated) base pipes, with surrounding wire wrap, as described above. However, in the sand control system 320B, gravel slurry conduits are used to conduct gravel packing between selected SMP devices 365b. Gravel slurry is then pumped into the annular regions 363. Thus, at least some of the sand screens 365a′ in FIG. 3B will be gravel packed.

In FIG. 3B, two types of gravel slurry conduits are shown. The first type is transport conduits 323, which are used for transporting slurry across sand control devices 365a′, 365b (or even zones 165a, 165b, etc.) during a gravel packing operation. The second type is packing conduits 328, which are used for delivering gravel slurry to a particular annulus 363 around selected fixed sand screens 365a′.

In practice, a compliant sand control device 365b may be equipped with at least one transport conduit 323, which in turn is connected to transport conduits 323 in the adjacent sand control devices, either compliant 365b or non-compliant 365a′. Selected non-compliant sand control devices 365a′ are equipped with at least one transport conduit 323, which is connected to the transport conduits 323 in the adjacent sand control devices, either compliant 356b or non-compliant 365a′. For an interval where gravel pack (or slurry) is to be installed, the corresponding non-compliant sand control device 365a′ is equipped with at least one packing conduit 328. The packing conduits 328 and transport conduits 323 are connected through a manifold (not shown) at the joint connections.

Each packing conduit 328 has at least one opening to the wellbore annulus 363. During a gravel packing operation, the gravel pack slurry flows through the transport conduit(s) 323, to the packing conduit(s) 328, and out from the opening to the wellbore annulus 363. The fluid in the gravel pack slurry leaks off into the screens of the fixed sand control devices 365a′, flows through openings in the base pipes, and returns to the surface in accordance with known gravel packing procedures. The gravel is left in the selected annuli 363 to form gravel packs.

The gravel pack slurry will continue flow through the transport conduit(s) 323 over the intervals where the compliant sand control devices 365b are located, or where the non-compliant sand control devices 365a′ are located and which are to be left without gravel pack.

In the sand control system 300B of FIG. 3B, at least some of the compliant 365b and non-compliant 365a′ sand control assemblies are alternated along the zone of interest 165a. This allows the operator to obtain the unique and novel benefit of multiple fixed sand screens 365a′, with or without the expense and complexity of gravel packing, while also preventing the cross-migration of small particles and fines through the use of shape memory polymer devices 365b. Thus, if one sand screen joint (or set of joints) 365a becomes clogged, the remaining sand screen joints (or sets of joints) 365a′ will not become clogged by the same migrating particles or fines. The shape memory polymer devices 365b have the additional benefits of being economical enough that multiple SMP devices 365b may be used instead of isolation packers, while also permitting formation fluids (such as hydrocarbon fluids) to flow through the polymer material and enter the bore 350 of the sand control system 320B.

FIG. 4A presents a side, cross-sectional view of a compliant sand control assembly 420 as may be used in the sand control systems 300A, 300B of the present invention, in one embodiment. The sand control assembly 420 exists for the purpose of filtering formation particles, e.g., clay particles and sand, from the formation fluids. In this view, the sand control assembly 400 is in its run-in position within a wellbore.

In FIG. 4A, a horizontal view of a wellbore 400 is shown. The wellbore 400 is formed along a formation 150. The compliant sand control assembly 420 has been run into the wellbore 400. The compliant sand control assembly 420 includes a perforated base pipe 410. The base pipe 410 includes a plurality of openings 445 through which reservoir fluids are received.

Secured to the perforated base pipe 410 along an outer diameter is a shape memory polymer material 430, or SMP. The SMP material 430 is designed to expand in response to a wellbore condition. In the view of FIG. 4A, the SMP material 430 is in its retracted (or non-actuated) condition.

In general, shape memory materials are so-called “smart materials” that have the ability to return from a deformed state (temporary shape) to their original (permanent) shape in response to an external stimulus. A common stimulus is a temperature change. In addition to temperature change, the shape memory effect of these materials may also be triggered by an electric or magnetic field, light or a change in pH. Shape-memory polymer materials (SMP's) cover a wide property range from stable to biodegradable, from soft to hard, and from elastic to viscoelastic to rigid, depending on the structural units that constitute the SMP material. SMP materials include thermoplastic and thermoset (covalently cross-linked) polymeric materials.

U.S. Pat. No. 7,318,481 assigned to Baker Hughes Inc. of Houston, Tex. discloses a self-conforming expandable screen which comprises a thermosetting open cell shape-memory polymeric foam. The foam material composition is formulated to be actuated (or expanded) at a desired transition temperature that is slightly below the anticipated downhole temperature at the depth at which the assembly will be used. This causes the conforming foam to expand at the temperature found at the desired depth. The SMP material 430 of FIG. 4A is preferably of this nature.

When shape memory polyurethane is used as a downhole device, it is preferred that the device remains in an altered geometric state during run-in until it reaches a desired downhole location. Usually, downhole tools traveling from the surface 101 to a desired zone 165a in a downhole formation 150 take hours or even days. Thus, it is important to match the onset temperature of the SMP material 430 with the expected downhole temperatures.

In the illustrative arrangement of FIG. 4A, the SMP material 430 is secured to the base pipe 410 by means of a billet 435. The billet 435 will have its own set of perforations (not shown) to permit an ingress of fluids towards the slots 445 in the base pipe 410 during a production operation. It is understood that, when actuated, the SMP material 430 itself will also be permeable to reservoir fluids.

FIG. 4B is another side, cross-sectional view of the compliant sand control assembly 420 of FIG. 4A. Here, the sand control assembly 420 is in its actuated state. This means that the shape memory polymer material 430 is in its expanded state, creating a substantial seal with the surrounding open hole formation 150. This, in turn, prevents the migration of formation fluids across the sand control assembly 420.

In operation, as the sand control assembly 420 is run into the wellbore 400, and after an optional sufficient amount of time at the sufficient temperature at or above the transition temperature, the shape-memory material 430 expands. The material 430 expands from the run-in shape position of FIG. 4A to a recovered or actuated position of FIG. 4B, having an expanded thickness. In so doing, the shape-memory material 430 engages the inner wall surface of the wellbore 400.

Additional information concerning the use of SMP material in a wellbore as a sealing material is found in U.S. Patent Publ. No. 2011/0232901 entitled “Variable TG Shape memory Polyurethane for Wellbore Devices,” U.S. Patent Publ. No. 2012/0067587 entitled “Polymer Foam Cell Morphology Control and Use in Borehole Filtration Devices” and U.S. Patent Publ. No. 2015/0068760 entitled “Multi-Layered Wellbore Completion for Methane Hydrate Production.” Any of the SMP devices described in those published applications, or their variations, are suitable for use as the compliant sand control assemblies 325b of FIG. 3A and 325b of FIG. 3B. It is understood that the current inventions are not limited to the type of SMP material used or the manner in which the SMP material is actuated or the configuration of the compliant sand control assemblies with SMP material unless so stated in a claim. The compliant sand control assembly in the current invention can include any type of permeable material or method capable of being compliant to wellbore, not limited by SMP.

It is noted that the compliant sand control assembly 420 may optionally have an intermediate filtering layer. The filtering layer may be a wire mesh screen, a ceramic screen, a woven mesh screen, or other filtering material. The intermediate filtering layer (such as that shown at 560 in FIG. 5) resides along a substantial length of the base pipes 410 and, preferably, under at least the length of SMP material 430.

Other compliant sand control assemblies may be used in the systems 300A, 300B besides those employing SMP material. These include PetroGuard Swell, Darcy screen, and other types of expandable screens.

FIG. 5A presents a side, cut-away view of a fixed sand control assembly 520 as may be used in the sand control system 300A of the present invention, in one embodiment. The sand screen assembly 520 resides within a wellbore 500. The sand screen assembly 520 does not include a material that may be actuated or extruded into sealing engagement with the surrounding wall of a wellbore; accordingly, it is considered “fixed.” The sand control assembly 520 exists for the purpose of filtering formation particles, e.g., clay particles and sand, from reservoir fluids.

The fixed sand control assembly 520 first comprises a base pipe 510. The base pipe 510 defines an elongated tubular body that extends substantially the length of the sand control assembly 520. The base pipe 510 forms a bore 550 that transports reservoir fluids to the surface 101. At least a portion of the base pipe 510 includes openings, or slots 545, for receiving the reservoir fluids and communicating them to the production tubing 130.

Longitudinal ribs 515 are disposed along an outer diameter of the base pipe 510. The longitudinal ribs 515 serve as a support layer for a surrounding wire wrap screen 530. The height of the ribs 540 establishes a drainage volume through which reservoir fluids flow under the wire wrap screen 530.

The plurality of longitudinal ribs 515 is secured in position around base pipe 510 by the wire wrap screen 530, which is wrapped transversely and helically around the plurality of longitudinal ribs 515. By securing the longitudinal ribs 515 directly against base pipe 510, the sand control screen 530 becomes securely held on the base pipe 510 without the need for welding of the screen 530 to the base pipe 510.

The sand screen 530 is designed to filter sand from fluid flowing into the bore 550. For example, reservoir fluids flowing into wellbore 100A, 100B from formation 150 passes through the sand control screen 530 which filters out sand while allowing the reservoir fluid passage into well equipment.

Optionally, a supplemental filter media 560 is disposed around the longitudinal ribs 515. By way of example, the supplemental filter media 560 may comprise a cloth material, such as a woven wire cloth, although other types of filter media may be employed. In some embodiments, the supplemental filter media 560 is deployed directly against wire screen 530, although one or more standoff layers may be positioned between wire screen 530 and the supplemental filter media 560. The supplemental filter media 560 may be formed into a tubular element sized to fit closely over the outside diameter of the transversely wrapped wire screen 530.

Additionally, a protective shroud 580 may be disposed around the supplemental filter media 560 to protect the filter media 560 while still allowing flow of reservoir fluids therethrough. In one example, the protective shroud 580 is a metal tube having multiple micro-openings or perforations 585 to facilitate inflow, or outflow, of fluid. The outer, protective shroud 580 may be tightly positioned around and against the supplemental filter media 560, although other embodiments employ one or more standoff layers between the supplemental filter media 560 and the protective shroud 580.

FIG. 5B is a cross-sectional view of the fixed sand screen assembly 520 of FIG. 5A, taken across line B-B. FIG. 5B illustrates the interior bore 550 of the base pipe 510 along which fluids may be produced and/or injected. FIG. 5B also shows a surrounding wellbore wall 570. The sand screen assembly 520 is intended to reside generally concentrically within the wellbore wall 570.

The cross-sectional view shows a plurality of flow channels 562 which are created between longitudinal ribs 515. In the embodiment illustrated, flow channels 562 are oriented generally in an axial direction to enable axial flow of fluid along the space between the supplemental filter media 560 and the base pipe 510. The spacing between adjacent longitudinal ribs 515, as well as the spacing between adjacent wraps of wire screen 530, is greater than the pore size of the supplemental filter media 560. If, for example, the supplemental filter media 560 comprises woven wire, the spaces or pores through the woven wire are selected to restrict particles of smaller size than would be restricted by the spacing between longitudinal ribs 515 or between the wraps of wire screen 530.

FIG. 6A presents a side, cross-sectional view of a fixed sand control assembly 520′ as may be used in the sand control system 300A of the present invention, in an alternate embodiment. The sand control assembly 520′ likewise exists for the purpose of filtering formation particles, e.g., clay particles and sand, from the formation fluids. The sand screen assembly 520′ is similar to the sand screen assembly 520, and like parts are indicated herein by like reference numbers.

The fixed sand control assembly 520 again includes a base pipe 510 having a plurality of perforations 545. The sand control assembly 520′ also includes the longitudinal ribs 515, the wire screen 530 and the surrounding supplemental filter media 560. However, instead of using the surrounding outer shroud 580, the sand control assembly 520′ employs another layer of ribs 535 that support still another outer wire screen 590.

The ribs 535, 515 provide drainage layers under the wire screens 590, 530 respectively. The ribs 535, 515 may have circular cross-sectional shapes, triangular cross-sectional shapes, delta cross-sectional shapes, or other suitable cross-sectional shapes. The two layers of screens 590, 530, coupled with the supplemental filter layer 560, provide for multi-layer filtering of sand particles as reservoir fluids enter the perforations 545 in the base pipe 510.

FIG. 6B is a cross-sectional view of the fixed sand screen assembly 520′ of FIG. 6A, taken across line B-B. FIG. 6B illustrates the interior bore 550 of the base pipe 510 along which fluids may be produced and/or injected. FIG. 6B also shows the surrounding wellbore wall 570.

Additional arrangements for a multi-layered fixed sand control assembly are disclosed in U.S. Pat. Nos. 8,567,498 and 8,464,793, each of which is incorporated herein by reference in its entirety. It is understood that inventions herein are not limited to any particular type of fixed sand control assembly unless expressly stated in a claim.

FIG. 7 is a perspective view of another fixed sand control assembly 700 as may be used in the sand control system 300A of the present invention. The sand control assembly 700 likewise exists for the purpose of filtering formation particles, e.g., clay particles and sand, from the formation fluids. The sand control assembly 700 beneficially offers more than one fluid flow compartment so as to equalize fluid pressure along the filter screen. The sand control assembly 700 (sometimes referred to as a sand screen joint) is taken from FIG. 3 of U.S. Patent Publ. No. 2014/0262260 entitled “Sand Control Screen Having Improved Reliability.”

The fixed sand control assembly 700 first includes a filtering medium. The filtering medium is divided into primary sections 710 and secondary sections 720. In the arrangement of FIG. 7, two groupings of primary 710 and secondary 720 sections are indicated. Each of these groupings represents a “compartment,” indicated at brackets 70A and 70B. In one aspect, each compartment 70A, 70B is between about 5 feet (1.52 meters) and 10 feet (3.05 meters) in length.

In order to transport fluids to the surface 101, the sand screen joint 700 also includes a base pipe. The base pipe defines an elongated tubular body having at least one permeable section and at least one impermeable section within each compartment 70A, 70B. Each permeable section preferably comprises circular holes or slots for receiving formation fluids into a bore. The base pipe is not visible in the view of FIG. 7; however, the base pipe is shown at 335b in FIG. 4A of U.S. Patent Publ. No. 2014/0262260, and at 335p in FIG. 4B thereof. The base pipe 335b represents a section of blank pipe, while base pipe 335p is a section of perforated or slotted pipe. The base pipes 335b and 335p transport formation fluids towards the surface 101.

To effectuate the transport of formation fluids to the surface 101, the base pipes 335b, 335p are in fluid communication with a tubular body 330. The tubular body 330 represents sections of “blank” tubular members. The base pipes 335b, 335p and the tubular body 330 may be the same tubular member. The tubular body 330, in turn, is in fluid communication with the production tubing (shown illustratively at 130 in FIGS. 1A and 2). The tubular body 330 is threadedly connected to the production tubing 130 at or below the packer 206 to form a fluid conduit that delivers production fluids to the surface 101.

Portions of the tubular body 730 extend from both ends of the compartments 70A, 70B. Split rings 705 may be applied at opposing ends of the compartments 70A, 70B to create a seal between the compartments 70A, 70B and the tubular body 730. The split rings 705 are described more fully in connection with FIGS. 5A and 5B of U.S. Patent Publ. No. 2014/0262260.

In the sand screen joint 700, the filtering function of the joint 700 is substantially continuous along the joint's length. However, the base pipes are not continuous; rather sections of blank base pipe 335b and perforated base pipe 335p are staggered with sections of primary 710 and secondary 720 filtering conduit. The blank base pipe 335b resides within the primary filtering medium 710 while the perforated base pipe 335p resides within the secondary filtering medium 720.

The first filtering conduit 710 circumscribes the blank base pipe and forms a first annular region between the base pipe 335b and the first filtering conduit. The filtering medium 710 is constructed to filter sand and other formation particles while allowing an ingress of formation fluids. The second filtering conduit 720 is longitudinally adjacent to the first filtering conduit 710. The second filtering conduit circumscribes the permeable base pipe and forms a second annular region between the base pipe 335p and the second filtering conduit 720. The filtering medium 720 is also constructed to filter sand and other formation particles while allowing an ingress of formation fluids.

In addition, each compartment 70A, 70B also includes a tubular housing 740. The tubular housing 740 is a section of blank pipe that sealingly circumscribes the second filtering conduit 720. The tubular housing 740 forms a third annular region between the second filtering medium 720 and the surrounding housing 740.

Each compartment further optionally comprises an under-flow ring (not shown). The under-flow ring 715 is disposed longitudinally between the first filtering conduit 710 and the second filtering conduit 720 for directing fluid flow from the first annular region into the third annular region. The under-flow ring 715 comprises a short tubular body having an inner diameter and an outer diameter. The outer diameter sealingly receives the blank tubular housing 740 at an end. The under-flow ring 715 has flow channels that direct formation fluids from the first annular region into the third annular region.

As another option, a section of blank pipe 730 is disposed between the under-flow ring and the second filtering conduit 720. For example, a section of blank pipe 730 may be an extension of the impermeable base pipe between the under-flow ring and the second filtering conduit 720. The blank pipe permits a circumferential dispersion of fluids as the fluids travel from the first annular region to the third annular region.

In operation, formation fluids flow through the first filtering conduit 710 and into the first annular region around the blank (non-perforated) base pipe 335b. The fluids then flow through the channels of the under-flow ring 715 and into the third annular region (beneath the tubular housing 740). From there, fluids flow through the second filtering conduit 720 and into the second annular region (around the permeable base pipe 335p). The fluids then pass through the slots of the perforated base pipe 335p for transport to the surface.

The fixed sand control assembly 700 of FIG. 7 is between 10 feet (3.05 meters) and 40 feet (12.19 meters). It is preferred that each sand screen joint 700 have at least two, and possibly even six, compartments 70A/70B. In one preferred arrangement, the sand screen joint 700 is 30 feet (9.14 meters) long, and comprises a first primary section 710, followed by a first secondary section 720, followed by a second primary section 710, followed by a second secondary section 720, with each of these four sections being about six feet in length. The remaining six feet is taken up by under-flow rings 715, baffles (such as baffle 350 of FIGS. 4B and 7), threaded connection ends (not shown), weld rings 707, and extensions of blank pipe 730. The extensions of blank pipe 730 would be for baffle extensions, compartment dividers, and connection make-up in field installation.

The illustrative multi-compartment arrangement for the joint 700 of FIG. 7 provides a back-up for fluid filtration. If a portion of the filtering medium in the primary conduit 710 fails, sand in the formation fluids will nevertheless be filtered before entering the perforated base pipe. In this respect, formation fluids are still forced to flow along the blank base pipe and towards the secondary section 720, where the fluids will then pass through the filtering medium of the secondary filtering conduit 720 and into the perforated base pipe. In addition, fluid pressure acting along the second filtering conduit 720 is equalized by the underflow rings 715, thereby reducing hot spots.

The sand control assembly 700 represents one embodiment of a fixed sand screen joint that creates a tortuous flow path for production fluids. Other arrangements for creating a tortuous flow path are described in U.S. Patent Publ. No. 2014/0262260 and U.S. Patent Publ. No. 2014/0231083.

It is also noted that sand screen joints having transport tubes and packing tubes should be used in connection with the sand control system 320B of FIG. 3B. Illustrative sand screen joints are shown and described in U.S. Pat. No. 7,938,184 issued Aug. 11, 2008, entitled “Wellbore Method and Apparatus for Completion, Production and Injection.” This application is incorporated herein by reference in its entirety. ICD screens and sintered metal screens may also be used.

Based on the above descriptions, a method for completing a wellbore is provided herein. The method is presented in FIG. 8. FIG. 8 provides a flow chart presenting steps for a method 800 of completing a wellbore in a subsurface formation, in certain embodiments. The wellbore preferably includes a lower portion completed as an open-hole. Preferably still, the open hole portion is completed horizontally. More preferably, the wellbore is an extended length wellbore that traverses multiple zones across more than 5,000 feet of horizontal or deviated hole.

In one aspect, the method 800 first includes providing a plurality of compliant sand control assemblies. This is shown at Box 805. The compliant sand control assemblies are constructed in accordance with the compliant sand control assemblies described above in their various embodiments. In this respect, each compliant sand control assembly has one or more joints of slotted or perforated base pipe threadedly connected in series, and a shape memory polymer material, or SMP material, around the slotted base pipe along at least a portion of its length.

The method 800 also includes providing a plurality of fixed sand control assemblies. This is seen at Box 810. The fixed sand control assemblies are also constructed in accordance with the various fixed (or non-compliant) sand control assemblies described above in their various embodiments. In this respect, each fixed sand control assembly also has one or more joints of slotted or perforated base pipe threadedly connected in series, and, optionally, a surrounding filter screen along at least a portion of its length.

The method 800 next includes running the compliant sand control assemblies and the fixed sand control assemblies into a wellbore. This is provided at Box 815. The sand control assemblies are run into the wellbore in such a manner that the compliant sand control assemblies and the fixed sand control assemblies are placed in the wellbore in alternating relation. In one aspect, each compliant sand control assembly is between 8 and 12 feet in length, while each fixed sand control assembly is between about 25 and 150 feet in length.

The method 800 may also include the step of identifying rock properties of certain zones along the wellbore. This is seem at Box 820. Such rock properties may include, for example, lithology, permeability, porosity, pressure and consolidation.

The method 800 then includes locating the compliant sand control assemblies along pre-selected zones along the wellbore according to the identified rock properties. This is indicated at Box 825. For example, certain zones may have an unconsolidated rock matrix, or may have excessively fine particles. In that instance, the operator may locate one of the compliant sand control assemblies at opposing edges of such zones. This is seen at Box 830. Additionally, the operator may place one or more compliant sand control assemblies intermediate the two opposing compliant sand control assemblies. This is shown at Box 835. All of this is designed to mitigate the flow of loose sand and fines across joints of sand screen.

The method 800 additionally includes actuating the SMP material along the compliant sand control assemblies. This is provided at Box 840. As noted, the SMP material is designed to expand into contact radially with a wellbore wall downhole in response to an environmental or wellbore condition. The wellbore condition may be, for example, a certain temperature, a certain pressure, a certain wellbore fluid, exposure to a certain fluid injected into the wellbore, or combinations thereof.

The method 800 also includes producing hydrocarbon fluids through the base pipes of the sand control assemblies along zones of interest within the wellbore. This is given at Box 845. Producing hydrocarbon fluids causes hydrocarbon fluids to travel into the base pipes, through the production tubing, and up to the surface.

The method 800 may further optionally include the step of conducting a gravel packing operation between two selected compliant sand control assemblies. This is seen at Box 850. Such an operation would require the injection of sand slurry through shunt tubes in order to bypass the expanded SMP material. It is understood by those of ordinary skill in the art that such an operation would require the use of a crossover tool for selectively circulating gravel slurry into the annular region between the sand control assemblies and the bore of the base pipes. It is further understood that such an operation would require the use of shunt tubes and packing tubes for the delivery of slurry into isolated zones between actuated SMP material.

The method 800 may further optionally include placing tracer material within an annular flow path along the sand control assemblies. This is given at Box 855. Those of ordinary skill in the art will understand that tracer material is microscopic (and even nanoscopic) elemental material that may be seeded into a wellbore at selected locations. Tracer materials may be acquired from ResMan AS of Stavanger, Norway. Tracer materials may also be obtained from and Tracero Ltd., located in Billingham, United Kingdom.

In one embodiment, the tracer material is placed adjacent a selected compliant sand control assembly, or more than one selected compliant sand control assembly. The tracer material is preferably placed proximate openings in the base pipe. In another embodiment, the tracer material is placed adjacent a fixed sand screen assembly, or more than one selected fixed sand control assembly. The tracer material is again preferably placed proximate openings in the base pipe. Preferably, the tracer material is seeded adjacent to or within an in-flow control device along a sand control assembly to insure dissolution. As wellbore fluids are produced to the surface, the tracer material is dissolved and produced to the surface along with the wellbore fluids.

Where a tracer material is employed, the method 800, will further include analyzing the wellbore fluids to identify tracer material. This is indicated at Box 860. Analysis of the wellbore fluids to identify tracer materials will inform the operator of which sand control assemblies are receiving production fluids. More importantly, analysis of the wellbore fluids to identify tracer materials will inform the operator as to which sand control assemblies are not receiving wellbore fluids.

Optionally, the method 800 further includes providing a packer assembly between designated sand control assemblies. This is seen at Box 865. Preferably the packer assemblies are impermeable packers placed between fixed sand screen joints.

The packer assembly may include at least one, and preferably two, mechanically-set packers. These represent an upper packer and a lower packer. Each packer will have an inner mandrel, and a sealing element external to the inner mandrel. Each mechanically-set packer has a sealing element that may be, for example, from about 6 inches (15.2 cm) to 24 inches (61.0 cm) in length.

Alternatively or in addition, the packer assembly also includes at least one swellable sealing element. The swellable packer element is disposed intermediate a pair of mechanically-set packers or replaces the mechanically-set packers. The swellable packer element is preferably about 3 feet (0.91 meters) to 40 feet (12.2 meters) in length. In one aspect, the swellable packer element is fabricated from an elastomeric material. The swellable packer element is actuated over time in the presence of a fluid such as water, gas, oil, or a chemical. Swelling may take place, for example, should one of the mechanically-set packer elements fails. Alternatively, swelling may take place over time as fluids in the formation surrounding the swellable packer element contact the swellable packer element.

The above method 800 may be used to more effectively produce wellbore fluids, primarily valuable hydrocarbon fluids, from an extended reach wellbore in a multi-zone completion. The method has particular utility in connection with the control of sand migration across zones of interest within a surrounding open-hole portion of a wellbore, reducing the need for multiple and expensive packer assemblies.

While it will be apparent that the inventions herein described are well calculated to achieve the benefits and advantages set forth above, it will be appreciated that the inventions are susceptible to modification, variation and change without departing from the spirit thereof. Improved methods for completing an open-hole wellbore are provided so as to seal off or to at least limit production from one or more selected subsurface intervals by using or actuating an in-flow control section along a sand control assembly.

Claims

1. A hybrid sand control system residing within a wellbore, comprising: a plurality of compliant sand control assemblies, each compliant sand control assembly comprising: an elongated base pipe, the base pipe having a first end and a second end, andat least one opening formed in the base pipe between the first and second ends, the opening being configured to allow an ingress of wellbore production fluids when positioned within the open hole portion, anda material placed along at least a portion of the length of the base pipe of the compliant sand control assembly, the material fabricated to engage a surrounding wellbore wall to control a migration of particles outside of the base pipes in response to an expansion force;a plurality of fixed sand control assemblies, each fixed sand control assembly comprising: at least one elongated base pipe, each base pipe having a first end and a second end and being in fluid communication with the base pipes of the plurality of compliant sand control assemblies,at least one opening formed in the base pipe between the first and second ends, the opening being configured to allow an ingress of wellbore production fluids when positioned within the open hole portion; anda filter medium disposed around each of the at least one base pipes of the fixed sand control assemblies, the filter medium extending substantially along the length of each corresponding base pipe without compliantly engaging the surrounding wellbore wall;wherein the compliant sand control assemblies and the fixed sand control assemblies are positioned along the open hole portion in alternating relation.

2. The sand control system of claim 1, wherein the open hole portion is formed horizontally.

3. The sand control system of claim 1, wherein each compliant sand control assembly is between 8 and 12 feet in length.

4. The sand control system of claim 3, wherein each fixed sand control assembly is between 25 and 150 feet in length.

5. The sand control system of claim 4, wherein the wellbore is an extended length wellbore that traverses multiple zones across more than 5,000 feet of open hole.

6. The sand control system of claim 1, wherein: the compliant sand control assemblies comprise expandable sand screens;the expandable material comprises the slotted metal base pipe and surrounding filter medium; andthe expansion force is a mechanical force applied from inside of the base pipes of the compliant sand control assemblies.

7. The sand control system of claim 1, wherein: each of the compliant sand control assemblies comprises a shape memory polymer device;the expandable material comprises a SMP material fabricated to assume a first run-in shape wherein the SMP material is in a contracted position, and then move to an expanded position; andthe expansion force is a change in wellbore condition.

8. The sand control assembly of claim 7, wherein the change in wellbore condition is (i) the presence of selected wellbore fluids; (ii) a wellbore temperature; (iii) a wellbore pressure; (iv) an injected chemical, or (v) combinations thereof.

9. The sand control system of claim 8, wherein each compliant sand control assembly further comprises an intermediate filtering layer residing between the base pipe and the surrounding shape memory polymer material along a substantial length of the base pipe.

10. The sand control system of claim 9, wherein the intermediate filtering layer is a wire mesh screen or a ceramic screen.

11. The sand control system of claim 1, wherein the filter medium of each fixed sand control assembly comprises a wire wrapped screen, a sintered metal screen or a ceramic screen.

12. The sand control system of claim 1, wherein the filter medium of each fixed sand control assembly comprises longitudinal ribs, followed by a helically-wrapped wire screen, followed still by a woven wire cloth.

13. The sand control system of claim 12, wherein the filter medium of each fixed sand control assembly further comprises a protective shroud placed over the woven wire cloth.

14. The sand control system of claim 1, wherein the filter medium of at least one of the fixed sand control assemblies comprises two or more filtering compartments arranged along the base in adjacent relation to form a non-linear flow path.

15. The sand control system of claim 1, wherein (i) at least one of the fixed sand control assemblies comprises a tracer material proximate openings in the base pipe, (ii) at least one of the compliant sand control assemblies comprises a tracer material proximate openings in the base pipe, or (iii) both (i) and (iii).

16. The sand control system of claim 15, wherein the tracer material resides proximate an in-flow control device within each corresponding sand control assembly.

17. The sand control system of claim 1, wherein: each fixed sand control assembly is made up at least two individual joints of sand screen threadedly connected together; andeach such joint is between 25 and 40 feet in length.

18. The sand control system of claim 1, wherein at least one compliant sand control assembly and at least one fixed sand control assembly comprise one or more transport conduits residing along an annular flow path external to the base pipe, the transport conduits each having a bore for communicating gravel slurry through the sand control system during a gravel packing operation.

19. The sand control system of claim 18, wherein at least one fixed sand control assembly also comprises one or more packing conduits residing along the annular flow path external to the base pipe, the packing conduits being manifolded to the transport conduit and having at least one opening to a wellbore annulus so as to permit a gravel pack slurry flowing through the transport conduits to also flow through the packing conduits and out through openings to a wellbore annulus during the gravel packing operation.

20. The sand control system of claim 1, wherein each of the compliant sand control assemblies is located along a pre-selected zone within the open hole portion of the wellbore according to identified rock properties in the zone.

21. The sand control system of claim 20, wherein at least some of the plurality of compliant sand control assemblies are located at opposing edges of such pre-selected zones.

22. The sand control system of claim 21, wherein at least some of the compliant sand control assemblies are located intermediate two compliant sand control assemblies located at opposing edges of the pre-selected zones.

23. A method of completing a wellbore, the wellbore having an open hole portion at a lower end, and the method comprising: providing a plurality of compliant sand control assemblies, each compliant sand control assembly comprising: an elongated base pipe, the base pipe having a first end and a second end, andat least one opening formed in the base pipe between the first and second ends, the opening being configured to allow an ingress of wellbore production fluids when positioned within the open hole portion, andan expandable material configured to engage a surrounding wellbore wall in response to an expansion force within the wellbore and to filter wellbore particles;providing a plurality of fixed sand control assemblies, each fixed sand control assembly comprising: at least one elongated base pipe, each base pipe having a first end and a second end,at least one opening formed in the base pipe between the first and second ends, the opening being configured to allow an ingress of wellbore production fluids when positioned within the open hole portion, anda filter medium disposed around each of the at least one base pipes of the fixed sand control assemblies, the filter medium extending substantially along the length of each corresponding base pipe without compliantly engaging the surrounding wellbore wall;running the compliant sand control assemblies and the fixed sand control assemblies into a wellbore such that the compliant sand control assemblies and the fixed sand control assemblies are run into the wellbore in alternating relation; andapplying the expansion force in order to engage the expandable material to the surrounding wellbore wall.

24. The method of claim 23, wherein the open hole portion is greater than 2,000 feet.

25. The method of claim 23, wherein the open hole portion is greater than 5,000 feet.

26. The method of claim 24, wherein the open hole portion is completed horizontally.

27. The method of claim 24, wherein each compliant sand control assembly is between 8 and 12 feet in length.

28. The method of claim 27, wherein each fixed sand control assembly is between about 25 and 150 feet in length.

29. The method of claim 28, further comprising: identifying rock properties of certain zones along the wellbore;locating the compliant sand control assemblies along pre-selected zones along the wellbore according to the identified rock properties.

30. The method of claim 29, further comprising: locating compliant sand control assemblies at opposing edges of such zones.

31. The method of claim 30, further comprising: locating compliant sand control assemblies intermediate two compliant sand control assemblies located at opposing edges of such zones.

32. The method of claim 29, further comprising: producing hydrocarbon fluids through the base pipes of the sand control assemblies along zones of interest, and up to the surface.

33. The method of claim 23, wherein: the compliant sand control assemblies comprise expandable sand screens;the expandable material comprises the slotted metal base pipe and a surrounding filter medium; andapplying the expansion force comprises applying a mechanical force from inside of the base pipes of the compliant sand control assemblies.

34. The method of claim 23, wherein: the compliant sand control assemblies comprises a shape memory polymer device;the expandable material comprises a SMP material fabricated to assume a first run-in shape wherein the SMP material is in a contracted position, and then move to an expanded position; andapplying the expansion force comprises exposing the SMP material to a wellbore condition.

35. The method of claim 34, wherein applying the expansion force to the SMP material comprises (i) exposing the shape memory polymer to wellbore fluids over time; (ii) exposing the shape memory polymer to wellbore temperatures over time; (iii) exposing the shape memory polymer to wellbore pressures over time; (iv) exposing the shape memory polymer to an injected chemical, or (v) combinations thereof.

36. The method of claim 34, further comprising: after actuating the shape memory polymer material, injecting gravel slurry into annular regions formed between at least some of the fixed sand control assemblies and the surrounding wall of the wellbore in order to form isolated gravel pack regions between selected compliant sand control assemblies.

37. The method of claim 23, further comprising: placing tracer material within an annular flow path along openings in the base pipes of (i) at least one of the fixed sand control assemblies, (ii) at least one of the compliant sand control assemblies, or (iii) both;performing chemical analysis at a surface to identify the presence or absence of tracer material in production fluids; andcorrelating tracer material with zones along the open hole portion.

38. The method of claim 23, wherein the at least one of the sand control assemblies comprises (i) at least three of the fixed sand control assemblies, (ii) at least two of the compliant sand control assemblies, or (iii) both.

39. The method of claim 38, wherein: the at least one of the sand control assemblies comprises at least two of the fixed sand control assemblies; anda tracer material is placed proximate an in-flow control device of each of the at least two fixed sand control assemblies.

40. The method of claim 23, further comprising: providing a packer assembly between designated fixed sand control assemblies; andrunning the packer assembly into the wellbore during well completion; andactuating the packer assembly to further isolate zones of interest along the open hole portion of the wellbore.

41. The method of claim 40, wherein the packer assembly comprises (i) at least one mechanically-set packer, (ii) a swellable packer, or (iii) both.

42. The method of claim 23, wherein: at least one of the compliant sand control assemblies and at least one of the fixed sand control assemblies comprises one or more transport conduits residing along an annular flow path external to the base pipe, the transport conduits each having a bore for communicating gravel slurry through the assemblies during a gravel packing operation; andat least one of the fixed sand control assemblies also comprises one or more packing conduits residing along the annular flow path external to the base pipe, the packing conduits being manifolded to the transport conduits and having at least one opening to a wellbore annulus so as to permit a gravel pack slurry flowing through the transport conduits to also flow through the packing conduits and out through openings to the wellbore annulus during the gravel packing operation.

43. A method of completing a wellbore, the wellbore having an open hole portion at a lower end, and the method comprising: providing a plurality of compliant sand control assemblies, each compliant sand control assembly comprising: an elongated base pipe, the base pipe having a first end and a second end,at least one opening formed in the base pipe between the first and second ends, the opening being configured to allow an ingress of wellbore production fluids when positioned within the open hole portion, anda shape memory polymer material placed along at least a portion of the length of the base pipe of the compliant sand control assembly, the shape memory polymer fabricated to: assume a first run-in shape wherein the shape memory polymer material is in a contracted position, and then move to an expanded position in response to a wellbore condition to control sand migration along the wellbore, andin its expanded position, permit an ingress of wellbore fluids to the base pipe;providing a plurality of fixed sand control assemblies, each fixed sand control assembly comprising: at least one elongated base pipe, each base pipe having a first end and a second end,at least one opening formed in the base pipe between the first and second ends, the opening being configured to allow an ingress of wellbore production fluids when positioned within the open hole portion, anda filter medium disposed around each of the at least one base pipes of the fixed sand control assemblies, the filter medium extending substantially along the length of each corresponding base pipe without compliantly engaging the surrounding wellbore wall;running the compliant sand control assemblies and the fixed sand control assemblies into a wellbore such that the compliant sand control assemblies and the fixed sand control assemblies are run into the wellbore in alternating relation; andactuating the shape memory polymer material into its expanded condition, wherein the shape memory polymer radially engages the surrounding wellbore wall of the open hole portion of the wellbore in response to the wellbore condition such that the shape memory polymer material permits an ingress of wellbore fluids into the base pipe while filtering selected solid material.

44. The method of claim 43, wherein: the open hole portion is greater than 5,000 feet;the open hole portion is completed substantially horizontally;each compliant sand control assembly is between 8 and 12 feet in length;each fixed sand control assembly is between about 25 and 150 feet in length; andactuating the shape memory polymer material comprises (i) exposing the shape memory polymer to wellbore fluids over time; (ii) exposing the shape memory polymer to wellbore temperatures over time; (iii) exposing the shape memory polymer to wellbore pressures over time; (iv) exposing the shape memory polymer to an injected chemical, or (v) combinations thereof.